In 2024, Brazil was the ninth-largest oil producer in the world, as can be verified in the International Energy Agency’s Oil 2025 report. From November 2024 to November 2025, average daily crude oil production was 3.7 million barrels per day, while natural gas production averaged 175 million cubic meters per day, as published by Brazil’s National Agency of Petroleum, Natural Gas and Biofuels (ANP) in the Oil and Gas Production Bulletin (November 2025).Brazil’s 3P oil reserves (as of December 31, 2023) totaled 29.2 billion barrels of oil and 741 billion cubic meters of natural gas, as reported by ANP in the Bulletin of Oil and Natural Gas Resources and Reserves 2024.

According to the Brazilian Federal Constitution, the Federal government owns the reserves of oil and natural gas. The rights to explore and produce oil and natural gas in Brazil are granted under either the concession (governed by Law No. 9,478/1997) or production sharing regimes (pursuant to Law No. 12,351/2010).

The concession regime is applicable to onshore and offshore fields, except in areas where the production sharing regime is mandatory. In the concession regime, the contractor owns all the oil and gas that may be discovered and produced in the concession area and pays government takes to the Federal Government participations, such as: signature bonus, payment for occupying or retaining an area (in the case of onshore blocks), royalties and, in the case of large production fields, Special Participation.

The production sharing regime is adopted in operations carried out in the Pre-Salt Polygon (located offshore, as set forth in the applicable law) and in strategic areas as defined by the Federal Government. In the production sharing regime, the ownership of the produced oil is shared between the contractor and the federal government. The contractor bears all the costs of the project (CAPEX, OPEX and DECEX) and, in case of exploratory success, the contractor is reimbursed with a volume of hydrocarbons called “Cost Oil”. To calculate the share of oil and natural gas owned by the Federal Government and by the contractor, the volume corresponding to the royalties due and all necessary investment and operating expenses are deducted from the total production activities (Cost Oil). The difference, called “Profit Oil”, is shared between the companies participating in the consortium and the Federal Government, in the proportions set forth in the contract.

The risk of investing and finding – or not – oil or natural gas is borne by the contractor.

In both regimes, the Federal Government, through the National Oil, Natural Gas and Biofuels Agency (“ANP”) carries out public bidding rounds for the granting of oil and gas blocks for exploration and production. Bids are submitted for each individual block offered by ANP.

The selection criteria for the winning offer are specified in the tender notice. For the concession regime biddings, the criterion is usually based on the highest signature bonus offered to the government.  In production sharing biddings, the typical criterion is the highest percentage of Profit Oil offered to the Federal Government. In both cases, the winning offer is the one providing the highest value for the block.

The draft concession or production sharing contract, as applicable, is attached to the tender protocol. ANP executes the contract with each of the winning bidders.

In addition to the bidding rounds for the concession and production sharing regimes, ANP offers blocks for exploration and production under the Permanent Offer System. Indeed, the Permanent Offer System is the preferential system for the offer of areas for exploration and production of oil and natural gas.

The Permanent Offer System consists of the continuous offer of exploratory blocks and areas, onshore or offshore, under the concession regime, including blocks of fields relinqueshed to ANP or in the process of being relinqueshed, as well as of blocks offered in previous rounds and not awarded. The offer of blocks located in the Pre-Salt Polygon, in strategic areas or on the Continental Shelf (i.e.  located beyond 200 nautical miles) in the Permanent Offer System is subject to previous authorization from the National Council of Energy Policy (CNPE).

There are two types of Permanent Offer: Permanent Concession Offer and Permanent Production Sharing Offer, which is used according to the applicable contracting regime.

Parties interested in participating in the Permanent Offer shall submit their registration request in accordance with the terms of the tender notice. Any interested party whose  registration request is approved by the ANP Bidding Commission and who keeps their registration documents up to date will be considered a bidder.

A cycle of the Permanent Offer will be opened upon the approval of a Declaration of Interest accompanied by a bid bond, with a specific schedule being established so that bidders can participate in said cycle.

The schedule to be established by the ANP Bidding Commission for each cycle of the Permanent Offer shall observe a minimum period of 120 calendar days and a maximum of 180 calendar days between the date of publication of the approval of the first Declaration of Interest in the Official Gazette of the Federal Government and the date of the public bid presentation session.

In addition to standard clauses, the key features of concession contracts are:

a) Provisions regarding the exploration, development, and production phases (including the submission of plans, financial guarantees, phase durations, commencement dates, and penalties for non-compliance with applicable requirements);

b) Rules for the calculation and payment of Royalties and Special Participation;

c) Local Content requirements for each phase, representing the mandatory percentage of Brazilian goods and services to be procured by the contractor during exploration and production activities;

d) Decommissioning and abandonment procedures;

e) Governing law (Brazilian Law) and the designation of arbitration as the dispute resolution mechanism.

In addition to standard clauses, the key features of production sharing contracts are:

a) Rules for calculating Cost Oil;

b) Rules for calculating and sharing Profit Oil;

c) Rules for the calculation and payment of Royalties;

d) Provisions regarding the exploration, development, and production phases (including the submission of plans, financial guarantees, phase durations, and penalties for non-compliance);

e) Local Content requirements for each phase;

f) Decommissioning and abandonment procedures;

g) Governing law (Brazilian Law) and the designation of arbitration as the dispute resolution mechanism.

There are no significant amounts of shale gas being exploited in Brazil.

There is one shale crude and gas reservoir that is explored by a consortium of private companies, previously owned by Petrobras.

It is worth to note that in 2013, it was offered at the 12^nd  Bidding Round some blocks on shore for the exploration of shale gas, through fracking. The contract for the exploration and production of said blocks were not executed due to a decision of the judicial courts to suspend it.

Despite the above information, in 2014, ANP regulated through ANP Resolution No. 21 the main requirements for Unconventional Reservoir Hydraulic Fracturing Optimization.

There are no significant volumes of shale gas currently being produced in Brazil.

There is one shale oil and gas reservoir currently operated by a consortium of private companies, which was previously held by Petrobras.

It is worth noting that, in 2013, during the 12th Bidding Round, ANP offered certain onshore blocks for shale gas exploration through hydraulic fracturing (fracking). However, the exploration and production contracts for those blocks were not executed due to court decisions suspending the process.

Notwithstanding the above, in 2014 ANP issued Resolution No. 21/2014, establishing the main requirements for the optimization of hydraulic fracturing in unconventional reservoirs.

The key regulators of the oil and gas industry in Brazil are: the National Council of Energy Policy (“CNPE”); the Ministry of Mines and Energy, and; the National Oil, Natural Gas and Biofuels Agency (“ANP”).

Petrobras (Petróleo Brasileiro S.A.) is a publicly traded company in which the Federal Government is the controlling shareholder. Petrobras operates in the following areas: oil and gas exploration and production; refining; transportation and trading; petrochemicals; power generation; and biofuels production.

PPSA (Pré-sal Petróleo S.A.) is a wholly government-owned company, with the Federal Government as its sole shareholder. PPSA represents the Brazilian Government in production sharing contracts and is responsible for managing such contracts, as well as for marketing and selling the Federal Government’s share of oil and gas.

Only companies incorporated in Brazil and with their headquarters and management in Brazil are allowed to enter into concession agreements or production sharing agreements. However, there are no restrictions on foreign companies holding full ownership and control of their Brazilian subsidiaries.

Brazilian environmental regulations are based on the polluter-pays principle, which establishes that those who pollute, directly or indirectly, must bear full responsibility for compensating any environmental damage, and such analysis is based on strict liability.

Furthermore, potentially polluting activities, such as upstream activities, are subject to a three-phase environmental licensing process for oil and gas exploration and production:

• Preliminary License (LP);
• Installation License (LI); and
• Operation License (LO).

It is important to note that the issuance of these licenses requires extensive environmental studies, which must be submitted to and evaluated by the relevant environmental authorities. For upstream activities, obtaining the Preliminary License (LP) entails conducting an Environmental Impact Assessment (EIA) and preparing an Environmental Impact Report (RIMA), which must be reviewed and approved by the appropriate environmental authorities.

Licenses, if granted, stipulate specific conditions and limitations for conducting the activities. Notably, being awarded an exploration area in a bid and entering into a concession or production sharing contract does not automatically grant environmental licenses or create vested rights in licensing.

Licensing for potentially polluting activities may be conducted at the state level or at the federal level (by IBAMA) in certain situations, such as when the activity is performed on the Brazilian offshore continental shelf or spans two or more states. In any case, the environmental state and federal entities are independent from ANP and any other regulator.

Regarding the health and safety regimes, in addition to being required to follow industry standards, Brazilian operators must also observe mandatory laws, regulations, and normative acts issued by the Ministry of Labor, environmental entities, as well as ANP.

From a contractual standpoint, in summary, the contractor shall:

a) at its own expense and risk, obtain all licenses, authorizations, and permits required under applicable laws and regulations;

b) maintain a safety and environmental management system that complies with the best practices of the oil industry and applicable laws and regulations;

c) ensure the preservation of an ecologically balanced environment;

d) mitigate the occurrence of impacts and/or damages to the environment;

e) ensure the safety of operations for the protection of human life, the environment, and the Federal Government’s heritage;

f) ensure the protection of Brazilian historical and cultural heritage;

g) restore degraded areas in compliance with applicable laws and regulations and the best practices of the oil industry;

h) meet the operational safety and environmental preservation recommendations issued by ANP, pursuant to applicable laws and regulations;

i) implement a management system for social and environmental responsibility consistent with the best practices of the oil industry.

In addition to the signature bonus, paid prior to the execution date of the contract (concession or production sharing), the contractor shall pay the following government takes:

a) Royalties: The amount is calculated by multiplying three factors: (i) the royalty rate for the producing field, which ranges from 5% to 15% as defined by ANP; (ii) the monthly volume of oil and natural gas produced; and (iii) the reference price for hydrocarbons for the respective month, as established by ANP.

b) Special Participation: This payment is applicable to high-production fields and is based on: (i) the net revenue from quarterly production after specific deductions (royalties, exploration investments, operating costs, depreciation, and taxes); (ii) a progressive rate that varies according to field location, years of production, and the quarterly production volume.

c) Payment to Landowners: For onshore operations, landowners are entitled to a monthly payment ranging from 0.5% to 1% of the total hydrocarbon production from the area.

The primary CAPEX tax incentive for oil and gas E&P activities is REPETRO-SPED. This is a special customs and tax regime that grants federal tax relief and a reduction in State VAT (ICMS) on the permanent importation or temporary admission of specific assets listed by the Brazilian Federal Revenue Service, provided that certain conditions are met.

Furthermore, the Brazilian Congress has approved a Tax Reform concerning indirect taxes. Federal Social Contributions (PIS and COFINS), Excise Tax (IPI), State VAT (ICMS), and Municipal Service Tax (ISS) will be gradually replaced by a dual VAT system (CBS and IBS) and a Selective Tax between 2026 and 2032. As of 2033, only CBS, IBS, and the Selective Tax will be in effect.

Throughout the contract period, the contractor shall comply with Local Content requirements, as stipulated in the respective contract. These requirements vary according to the project phase (exploration, development, and production) and specify the percentage of the total value of goods and services that must be contracted from Brazilian suppliers for each phase.

The transportation of crude oil produced in Brazil and destined for export shall be carried out by a Brazilian shipping company.

There are various ordinances and regulations issued by ANP, the Brazilian Navy, and IBAMA that apply to the decommissioning of E&P installations.Under concession or production sharing contracts, the operator undertakes to fully decommission the facilities and abandon the area in accordance with applicable law and the relevant approvals. As part of the contractual framework, the operator must provide a financial guarantee (bond) to ensure sufficient funds are available for the decommissioning phase.

Decommissioning obligations typically include: (i) the removal of assets from the field (as a general rule, subject to specific exceptions and approvals); (ii) the indemnification of any damages arising from the activities; and (iii) the environmental recovery of the area and/or the monitoring of any assets authorized to remain in place.

The decommissioning plan must be approved by ANP and, for offshore fields, is also subject to review and approval by the Brazilian Navy and IBAMA (the federal environmental authority). The plan must be submitted to ANP well in advance of the commencement of decommissioning activities.

Oil pipelines may be classified as transfer pipelines or transport pipelines, as provided under Law No. 9,478/1997.

Transfer oil pipelines are those whose route serves a specific offshore E&P unit and, for that reason, their construction and operation are subject to the same rules set forth in the applicable E&P contract.

Transport oil or gas pipelines are those whose route may be used by multiple parties and, for that reason, their construction and operation are subject to ANP authorization, in accordance with ANP Ordinance No. 52/2015.

Law No. 14,134/2021 provides that the construction and operation of offshore and onshore gas pipelines used to transport natural gas from an offshore E&P unit to a natural gas processing plant are also subject to ANP authorization.

Third parties have the right to access oil and gas transport pipelines, as well as other essential infrastructure, such as oil and gas terminals and processing facilities. The rules governing third-party access are set out in the Petroleum Law, the New Gas Law, their related regulatory decrees, and the applicable ANP resolutions.

LNG liquefaction and LNG receiving terminals are subject to ANP authorization, as provided in Law No. 14,134/2021. Their construction and operation are subject to the applicable requirements set forth in ANP Ordinance No. 52/2015. Third-party access may apply, but its implementation is subject to applicable regulation and, where relevant, ANP determinations.

In Brazil, there are seven LNG receiving terminals in operation, all of which employ FSRUs. There are currently no LNG liquefaction terminals in Brazil.

Underground natural gas storage installations are subject to ANP authorization, as provided in Law No. 14,134/2021. Third-party access may apply, but its implementation is subject to applicable regulation and, where relevant, ANP determinations.

As of December 2024, Brazil has no operational underground natural gas storage facilities. However, there are projects under development, including initiatives in depleted offshore fields and onshore depleted reservoirs, with the first facility potentially entering operation in the near term.

The Brazilian gas transmission system totals 9,409 km, and the gas distribution network totals approximately 41,500 km. Both networks are spread across various states in the country.

The gas transmission system is owned and operated by private companies under authorizations granted by ANP, as provided in Law No. 14,134/2021. Transmission capacity is made available to third parties under open-access rules, and, under the same legal framework, the transmission operator is generally prohibited from engaging in gas trading (i.e., it must remain unbundled from competitive activities, subject to the applicable legal exceptions).

The gas distribution network is owned and operated by private and state-controlled companies under state-level concession agreements. Third parties may access the distribution network as free consumers, subject to the applicable state laws and regulations.

It is worth noting that, under the Brazilian Federal Constitution, the regulation of gas transportation/transmission is within the competence of the Federal Government, whereas the regulation of local piped gas distribution services is within the competence of the states in which the distribution network is located.

In April 2021, Law No. 14,134/2021, known as the New Gas Law, was enacted. This law aims to promote the natural gas industry in Brazil and contribute to increased competition, thus promoting a broad opening of the market.

The New Gas Law, together with other measures adopted by the Federal Government, seeks to consolidate advances in transforming a model that was, in practice, monopolistic into a competitive, open, and dynamic market, enabling price reductions, attracting new investments, access to infrastructure, and the development of pre-salt gas production.

Large-volume consumers, gas distribution companies, and trading companies have the option to purchase natural gas from any agent authorized by ANP as a natural gas trader, which includes the distribution company itself.

According to the Federal Constitution, the regulation of the downstream gas market is carried out by the states.

Many states have updated their local regulations to align them with the New Gas Law, particularly to ensure that consumers, as free consumers, have the right to purchase gas from any trading company authorized by ANP.

Law No. 14,993/2024 (“Future Fuel Law”), which establishes emissions-reduction targets for natural gas producers and importers through the acquisition of biomethane or guarantees-of-origin biomethane certificates;

Decree No. 12,153/2024, which amended Decree No. 10,172/2021 to update certain regulations under the New Gas Law. Key changes include: (i) new gas processing plants and offshore gas pipelines becoming subject to the same rules applicable to gas transmission pipelines, including restrictions on vertical integration, pricing mechanisms, and the requirement to conduct public calls prior to granting authorizations; (ii) ANP being entitled to limit gas reinjection in oil production; and (iii) the establishment of principles for non-discriminatory access to offshore gas pipelines, gas processing units, and underground natural gas storage facilities.

Law No. 15,075/2024 amends the Petroleum Law (Law No. 9,478/1997) to permit the transfer of certified “local content minimum” surpluses (in monetary values) between existing E&P contracts. This provision impacts how contractors and operators manage local content compliance, potentially allowing for portfolio-level optimization across contracts, and explicitly assigns implementation and oversight responsibilities to ANP.

Law No. 15,103/2025, which establishes the Energy Transition Acceleration Program (“PATEN”) and provides various incentives for the natural gas industry in Brazil.

The key challenges for the government and industry are:

(i) Decarbonization of the oil and gas industry in Brazil

The oil and natural gas industry in Brazil has competitive advantages for the energy transition. There is a common understanding that oil and natural gas will remain indispensable to ensure energy supply and the well-being of the population in the coming years. To respond to the global challenge of reducing emissions, O&G companies have already diversified their investments to include new low-carbon technologies, implemented measures to reduce emissions associated with their operations, and prioritized types of oil with lower carbon intensity. This is the case with Brazilian production: the country’s oil has a lower carbon intensity per barrel than most from other producing countries.

In addition, many companies in the O&G industry are likely exposed to compliance with Law No. 15,042/2024, which creates the Brazilian Greenhouse Gas Emissions Trading System. Such companies must comply with government-set emission targets and purchase carbon credits where applicable.

(ii) Strengthening of the natural gas market in accordance with the New Gas Law

Strengthening the natural gas market to increase competition and promote broad market opening will require infrastructure investments along the entire value chain. Although many projects are under development, it will be crucial that the applicable ANP regulatory framework is implemented promptly to support these initiatives.

(iii) Decommissioning of various E&P units

There are many E&P units that need to be decommissioned in the coming years. There are opportunities for scrap yards to be established in Brazil to support decommissioning activities. New companies must comply with local and international regulations.

(iv) Environmental licensing for E&P in the Equatorial Margin

The Equatorial Margin, located in the north of the country between the states of Amapá and Rio Grande do Norte, is Brazil’s new oil and gas frontier, with high production potential. The area is close to the fields of Guyana, French Guiana, and Suriname, which are known for their rich oil reserves.

On October 20, 2025, Ibama issued the operating license authorizing Petrobras to carry out offshore exploratory drilling in a certain area in the Equatorial Margin . The license followed the agency’s review of Petrobras’ updated plans and established environmental conditions to be observed during the operation, easing concerns and political tension associated with the licensing process.

Recent geopolitical tensions with relevance to global energy markets—including the Russia–Ukraine war, the Israel–Hamas conflict and broader Middle East instability, security disruptions in the Red Sea/Gulf of Aden affecting shipping routes, and broader U.S.–China strategic tensions—have influenced Brazil primarily through international price volatility (Brent-linked dynamics), import parity for refined products and LNG, and higher freight/insurance and logistics costs.

However, these geopolitical events have not, in themselves, led to the enactment of specific new Brazilian laws or regulations expressly designed as a direct response to such conflicts. Instead, Brazil has continued to rely on its existing legal and regulatory framework and on market mechanisms to manage short-term impacts, while pursuing broader, internally driven reforms and policies (e.g., decarbonization initiatives and sectoral regulatory updates) that are not formally framed as emergency measures triggered by geopolitical conflicts.

The Brazilian oil and natural gas industry possesses significant competitive advantages for the energy transition. The following key legislation and initiatives highlight the country’s evolving regulatory and operational landscape:

a) Law No. 8,723/1993: Stipulates that all gasoline consumed in Brazil must be mixed with 27% anhydrous ethanol. This limit may be increased to 35%, provided it is deemed technically feasible by the Executive Branch.

b) Law No. 13,576/2017 (RenovaBio): Established the National Biofuels Policy. Under ANP Resolution No. 791/2019, annual greenhouse gas (GHG) emissions-reduction targets were set for fuel trading. Fuel distributors must comply with these targets by purchasing Decarbonization Credits (CBIOs) on the market, which are issued by certified biofuel producers.

c) Law No. 14,993/2024 (Future Fuel Law – ProBioQAV): Created the National Sustainable Aviation Fuel Program to encourage the research, production, and use of Sustainable Aviation Fuel (SAF). Air operators are required to reduce GHG emissions in domestic operations through SAF usage, with targets starting at 1% in 2027 and increasing progressively to 10% by 2037.

d) Law No. 14,993/2024 (National Green Diesel Program – PNDV): Aims to foster the integration of green diesel into the national energy matrix. The National Energy Policy Council (CNPE) will determine the mandatory minimum volumetric share of green diesel in the total diesel sold to final consumers. While this specific percentage is pending definition, the law established that the biodiesel-to-diesel blend will be 15% as of March 2025, increasing annually to 20% by 2030. Notably, biodiesel and green diesel are classified as distinct biofuels under ANP regulations.

e) Law No. 14,993/2024 (Biomethane Incentives): Established the National Program for Decarbonization of Natural Gas Producers and Importers and Biomethane Incentives. The CNPE will set annual GHG reduction targets for the natural gas market, applicable to producers and importers, to be met through biomethane participation. This obligation takes effect on January 1, 2026, with an initial target of 1% (capped at 10%). Compliance is proven through the purchase of biomethane or the acquisition of Biomethane Guarantee of Origin Certificates (CGOB). This allows the biomethane molecule to be traded separately from its environmental attribute.

f) Law No. 15,042/2024: Created the Brazilian Greenhouse Gas Emissions Trading System (SBCE). This system applies to several O&G companies, requiring them to meet government-mandated emission targets or purchase carbon credits when applicable.

g) Law No. 14,948/2024: Established the National Low-Carbon Hydrogen Policy, providing a regulatory framework for production. Its objectives include: (i) encouraging diverse production pathways; (ii) promoting hydrogen as a driver for the energy transition; (iii) valuing hydrogen for both domestic supply and export; (iv) protecting the environment; and (v) attracting national and foreign investment.

h) Law No. 15,103/2025: Established the Energy Transition Acceleration Program (PATEN), which provides various incentives for the natural gas and renewable energy industries in Brazil.

Carbon Capture

Carbon Capture, Utilization, and Storage (CCUS) has been utilized by Petrobras since 2008. Currently, all 21 platforms operating in the Santos Basin pre-salt incorporate CCUS technology associated with Enhanced Oil Recovery (EOR), significantly reducing the carbon footprint of production. A consultation process was opened for a draft decree intended to regulate CCS/CCUS/BECCS activities under Law No. 14,993/2024; as of the date of this note, a final decree was not identified as published.

Hydrogen

In October 2024, Petrobras announced the construction of its first pilot plant for renewable hydrogen at the Vale do Açu Thermoelectric Plant in Rio Grande do Norte. Expected to begin operations in the first quarter of 2026, the plant will produce hydrogen via water electrolysis powered by solar energy, separating water molecules into hydrogen and oxygen using electric current.

As of January 2026, the implementing decree for Brazil’s low-carbon hydrogen framework (including Law No. 14,948/2024) is in the final drafting stage and has not yet been formally issued.