Oil, Gas and the Transition to Renewables 2025 Comparisons

The Brazilian Constitution of 1988 establishes the federal government’s ownership of petroleum and mineral resources located in the subsoil, on the continental shelf, and in the exclusive economic zone (Articles 20 and 176). Additionally, pursuant to the Constitution, oil and natural gas exploration and production activities, refining, the importation and exportation of by-products, maritime transportation of crude oil or by-products, and pipeline transportation of petroleum and natural gas are under the monopoly of the federal government (Article 177).

However, the federal government can contract with state-owned or private entities to conduct the petroleum activities referred to above, subject to certain conditions set forth in the applicable laws.

End of the Petrobras Monopoly

After several years of monopoly over petroleum activities exclusive to Petróleo Brasileiro SA (Petrobras) since 1953, governmental authorities concluded that keeping the federal government’s monopoly over the exploration and production of oil and natural gas could be an obstacle to the development of the petroleum industry.

Thus, aiming to provide legal mechanisms to attract both domestic and international private capital to Brazil, the Brazilian Congress enacted Constitutional Amendment No 9/95, which amended the first paragraph of Article 177 of the Constitution and allowed petroleum activities to be contracted by the federal government with state-owned or private entities (subject to certain conditions outlined in the applicable laws).

In this context, Law 9,478/97 (Petroleum Law) was enacted and, among other provisions, it implemented the concession regime for the awarding of E&P rights by the federal government in Brazil. A few years later, following the discoveries of huge oil reserves in the ultra-deep waters of the pre-salt layer in the Campos and Santos basins, announced by Petrobras in 2007, and following several discussions within the federal government and Congress about the best way to exploit those resources, Law 12,351/2010 (Pre-Salt Law) introduced the production sharing regime in Brazil, which applies to areas located within the pre-salt areas (within the limits of a defined pre-salt polygon) and to other strategic areas.

In addition, given the massive investments that Petrobras was required to make in the oil and gas sector, Law 12,276/2010 introduced the so-called Transfer of Rights (ToR) regime, which defined a special capitalisation of Petrobras at the time and gave Petrobras (upon consideration) the right to produce up to five billion BOE (barrels of oil equivalent) in certain pre-salt areas.

The following main governmental bodies regulate hydrocarbon activities:

• the Ministry of Mines and Energy (Ministério de Minas e Energia);
• the National Council of Energy Policy (Conselho Nacional de Política Energética); and
• the National Agency of Petroleum, Natural Gas and Biofuels (Agência Nacional do Petróleo, Gás Natural e Biocombustíveis).

The Ministry of Mines and Energy

The Ministry of Mines and Energy (MME) was originally established by Law 3,782/1960 and subsequently recreated by Law 8,422/1992, which governs its organisational structure. The MME’s main activities are focused on political co-ordination and interaction with its related entities, as well as executing production sharing agreements on behalf of the federal government. The MME promotes and supervises the implementation of public policies in various sectors, including energy, mining, oil, fuel and power, as well as nuclear energy.

The National Council of Energy Policy

The National Council of Energy Policy (CNPE) derives from the Petroleum Law. It is a joint ministerial entity, presided over by the Minister of Mines and Energy and formed by representatives of other ministries and relevant entities, such as the Energy Research Office (EPE). The CNPE is an advisory body that assists the President of Brazil in developing proposals for policies and guidelines in the energy sector. The CNPE is responsible for promoting the rational use of energy resources and ensuring a stable and consistent energy supply throughout the country.

The National Agency of Petroleum, Natural Gas and Biofuels

The National Agency of Petroleum, Natural Gas and Biofuels (ANP) is the regulatory agency for petroleum activities. It is connected to the MME and is part of the indirect public administration. The Petroleum Law created the ANP and has the authority to regulate, intervene and inspect petroleum activities, including:

• enacting regulations (eg, resolutions and ordinances);
• establishing administrative proceedings and applying penalties;
• issuing authorisations for petroleum activities; and
• promoting and disclosing geological and geophysical studies related to petroleum activities.

The ANP is also authorised to promote and organise bid rounds for the award of E&P rights, and to execute concession contracts on behalf of the federal government.

Brazil also has two state-owned companies related to E&P activities: Petrobras and Empresa Brasileira de Administração de Petróleo e Gás Natural and Pré-Sal Petróleo SA (PPSA).

Petrobras

Petrobras was established in 1953 by Law 2,004/1953, following a heated debate over the most suitable policy for oil and natural gas exploration and production (E&P) activities in Brazil. Petrobras had a monopoly with regulatory attributes for over four decades, until the market was opened in the late 1990s.

PPSA

PPSA is a state-owned company affiliated with the MME, the creation of which was authorised by Law 12,304/2010 and Decree No 8,063/2013. Its main purposes are the management of production sharing contracts (PSCs) – to which it is a party without assuming liabilities – and the management and marketing of the federal government’s share of oil and natural gas. The company also represents the federal government in unitisation matters in the pre-salt areas.

The regulatory framework for the petroleum sector in Brazil encompasses two main laws: the Petroleum Law and the Pre-Salt Law.

The Petroleum Law

The Petroleum Law was a major milestone for the Brazilian petroleum sector, both onshore and offshore, and implemented a concession regime for the awarding of E&P rights by the federal government. In this context, the Petroleum Law created the ANP and CNPE (and defined their authority), outlined the relevant bidding rules and procedures to be observed in the bid round and the main provisions of the concession contracts, and provided the government’s policy objectives for the rational use of the country’s energy resources.

The Pre-Salt Law

The Pre-Salt Law established an additional contractual regime – the production sharing regime – for fields located within Brazil’s pre-salt areas (offshore) and other strategic areas, granting Petrobras preferential rights to choose the areas in which the company intends to operate, as well as the relevant participating interest (minimum 30% PI). The Pre-Salt Law also allows ANP to issue unitisation rules, which have been consolidated under ANP Resolution 867/2022. Among other matters, unitisation agreements must address:

• local content obligations;
• tract participation of each party in a shared reservoir;
• payment of the government share;
• the redetermination process; and
• the joint development plan.

The ToR

The ToR (despite debates on its classification as another legal-fiscal regime) was also enacted by Law 12,276/2010, exclusively for Petrobras, to allow for its capitalisation.

Both the concession regime (governed by the Petroleum Law) and the production sharing regime (governed by the Pre-Salt Law) allow for the acquisition of E&P rights by any company that meets the requirements established by the ANP.

Such acquisitions may be direct (through participation in bid rounds promoted by the ANP) or indirect (through the acquisition of a participating interest in an E&P contract previously awarded in a bid round), subject to approval by the ANP or MME (the latter for PSCs).

The Concession Regime

The concession regime has been in effect since 1997, pursuant to the Petroleum Law. Under this regime, a concessionaire will carry out E&P activities at its own risk and expense. Access to the bid rounds is open to any company that meets the legal, technical and financial requirements established by the ANP. Operators must undergo a qualification process to operate onshore or offshore (shallow and/or deep waters), depending on their prior operating experience. For exploration blocks, the criteria used by the ANP to determine the winning bidders are based on a formula that considers the amount of signature bonus (80%) and the minimum exploratory programme (20%). For areas with marginal accumulations, the criterion used is only the signature bonus.

The ANP and the concessionaires enter into the concession contract. In addition to the payment of a signature bonus offered during the bid round, the concession contract determines the payment of the following:

• a retention fee that is proportional to the size of the concession area retained;
• royalties;
• special participation; and
• payment for occupation or retention of an area (onshore blocks).

For those areas located within the pre-salt polygon and others that are considered strategic, the CNPE decides whether a bid round will be held or whether Petrobras will be hired directly (in order to preserve the national interest and achieve other energy-policy objectives), in accordance with the Pre-Salt Law. In both cases, contracts are executed under the production-sharing regime. Bid rounds are also conducted by the ANP.

The Production Sharing Regime

Under the production sharing regime, a contractor will also carry out E&P activities at its own risk and expense. In the case of a commercial discovery, the contractor will have the right to be reimbursed for properly incurred E&P costs (cost oil) and will receive a percentage of the profits generated by the project (profit oil). The contractor’s share of project profits will be defined in the PSC.

Cost oil

The cost oil is the share of production costs that the contractor is entitled to recover (in the case of a commercial discovery) for costs it incurred and investments it made during exploration, appraisal, development, production and abandonment activities. The terms, conditions and limitations of the cost oil will be detailed in the PSC.

Profit oil

The profit oil is the share of production profits to be divided between the federal government and the contractor, and represents the difference between the total volume of production and the share of cost oil and royalties.

Signature bonus

In addition to royalty payments, the production sharing regime also establishes the payment of a signature bonus. Unlike the concession regime, the value of a signature will be determined in advance by the relevant PSC – it will not, however, be among the criteria used to determine the winners of a bid round. Instead, the criteria used by ANP to determine winning bidders during the production sharing regime’s bid rounds will be based exclusively on the highest share of profit oil offered to the federal government by the competing companies.

The applicable rules for a direct acquisition are outlined in the Petroleum Law or the Pre-Salt Law, and detailed in the tender protocols of each relevant bidding procedure. In the case of an indirect acquisition, the requirements set forth in the tender protocol of the most recent bidding procedure carried out by the ANP must be met.

The tender protocols outline the key phases of the bidding process. These include registration or expression of interest, qualification (which encompasses legal, technical, and financial assessments), submission of bid bond guarantees, public sessions for submitting offers (bids), payment of a signature bonus, and the awarding of the contract.

Since 1998, Brazil has consistently held bid rounds for the awarding of concessions and production sharing contracts. Brazil has also found time to innovate and has implemented the Permanent Offer system for the awarding of E&P rights under both concession and production sharing regimes.

The Permanent Offer System

The ANP approved the process of the permanent offering of areas in 2017, with the initial purpose of allowing, through a differentiated system, the development of relinquished fields and exploratory blocks that had not been awarded during past bid rounds under the concession regime. 

The innovative aspect of the Permanent Offer system is the on-demand bidding rounds, referred to as “Cycles”. Each Cycle encompasses a public session for the presentation of offers, only for those sectors that have expressed interest and accompanied their bid with a bid bond. Only bidders that undergo the registration process may submit an expression of interest for the ANP’s analysis. Five Cycles of Permanent Offer under the concession regime have already been held. The latest one took place in June 2025 and resulted in the award of 34 exploratory blocks with a total signature bonus of BRL989,261,000.96.

Following these positive results, the CNPE published Resolution 27 at the end of 2021, designating the Permanent Offer system as the preferred mechanism for offering E&P rights. The CNPE also authorised the ANP to appoint and include in the Permanent Offer, under the concession regime, any onshore and offshore blocks, in addition to the non-awarded and relinquished fields (or those in the process of being relinquished).

The same CNPE Resolution 27/2021 also established that this authorisation does not cover fields and blocks included in the pre-salt area or strategic areas. Pre-salt blocks may be exceptionally included in the Permanent Offer through a specific determination by the CNPE, which defines the parameters applicable to each field or block.

Registration or Qualification

The registration procedure is the first step to participate in the Permanent Offer. Completing an individual registration enables a company to participate in all Cycles of each Permanent Offer. This payment provides access to a sample of data from the sectors related to the Permanent Offer.

Only bidders who complete the registration process can submit an expression of interest, indicating the specific block they intend to bid on. A valid bid bond must accompany this expression of interest. To participate in the offer presentation for the current Cycle, bidders must adhere to the specific schedule announced by the ANP for that Cycle.

The qualification process for the winning bidders takes place after the public session for both concession and production sharing regimes.

The Bidding Process

The schedule of each Cycle of the Permanent Offer starts with the approval by the ANP of the first expression of interest and bid bond. To submit a bid during the public session, bidders must be registered and approved by the ANP and also meet one of the following criteria:

• have submitted a timely Expression of Interest with a valid bid bond;
• have submitted only a bid bond to the ANP and participate in a consortium with a bidder who submitted an Expression of Interest; or
• participate in a consortium with a bidder who submitted an Expression of Interest, even without submitting an Expression of Interest or bid bond themselves.

The bid bonds may be provided in the following categories:

• letter of credit;
• performance bond; and
• escrow account deposit.

The bids placed in a specific public session are ranked, and the winning bidder is announced (in the same public session). If the winning bidder is not qualified or fails to execute the relevant contract, the bid bond guarantees will be enforced, as applicable, and the penalties provided for in the tender protocol will be applied. In this case, the remaining classified bidders will be invited to express their interest in meeting the bid amount placed by the previous winning bidder. In addition, there is a possibility of reopening the public session for blocks that were not awarded.

Execution of the Contract

Winning bidders must proceed with the following main steps towards the execution of the relevant contract:

• submit proof of payment of the signature bonus, in accordance with the tender protocol;
• provide the ANP with financial guarantees for the minimum exploratory programme within the term established in the tender protocol; and
• provide the ANP with a performance guarantee, if necessary (applicable for an operator only, if its technical qualification was based on the experience of its economic group).

The bidding process is concluded with the execution of the contracts.

The Approval Process

The assignment of an E&P contract – full or partial – is allowed under Article 29 of the Petroleum Law and Article 31 of the Pre-Salt Law, provided that the assignee fulfils the technical, financial and legal requirements set forth by the ANP in the relevant E&P contract and the rules set forth in the tender protocol. The ANP’s prior approval is required before the assignment becomes effective. For PSCs, the ANP will issue a recommendation to the MME, which is the governmental body responsible for approving the assignment. PSCs also provide that, in any case of assignment by any contractor, the right of first refusal of the other contractors must be observed.

The Petroleum Law and Decree No 2,705/1998 stipulate that the exploration, development and production of petroleum are subject to payment of the following government deductions:

• a signature bonus (see 2.1 Forms of Private Investment: Upstream);
• royalties;
• special participation; and
• payment for occupation or retention of an area (in the case of onshore blocks).

Royalties

Under the concession regime, the basic rate for royalties is 10%, but this can be reduced by up to 5% depending on geological risks, expected production and other relevant factors. Resolution 853/2021 permits a reduction in the royalty rate to 5% for fields operated by small-sized companies and to 7.5% for fields operated by medium-sized companies, subject to approval by the ANP.

Under the production sharing regime, royalties are levied at a rate of 15%.

In both cases, the royalties are calculated based on the value of oil and natural gas production.

Special Participation

Special participation only applies to fields with large production volumes under the concession regime. Special participation is calculated based on the net revenue of the quarterly production of each field, after the deductions allowed by paragraph 1 of Article 50 of the Petroleum Law (royalties, exploration investments, operating costs, depreciation and taxes). The rates range from 0% to 40%.

Payment for Occupation or Retention

The amounts to be paid for occupancy or withholding of an area (only due under the concession regime) are calculated in Brazilian reals per square kilometre. They must be paid and adjusted annually, as of the date of execution of the concession contract.

In addition to the government deductions detailed in 2.3 Typical Fiscal Terms: Upstream, companies engaged in the petroleum industry are also subject to the payment of federal, state and municipal taxes levied in different situations.

Corporate Income Taxes

Brazilian companies are subject to corporate income taxes (IRPJ and CSLL) on their worldwide income. IRPJ is levied at a rate of 15%, with a surtax of 10% levied on the taxable income exceeding BRL240,000 a year, while CSLL is levied at a rate of 9%.

Brazilian companies may elect to pay IRPJ and CSLL on a deemed income determined by a percentage of their gross revenues (“presumed profit methodology” or PPM) or on their actual income, adjusted by add-backs and exclusions as determined by tax legislation (“actual profit methodology” or APM).

Brazilian companies engaged in the petroleum industry usually elect to use APM because it allows losses to be carried forward indefinitely, and it allows up to 30% of the taxable income of subsequent tax periods to be offset; in addition, it is mandatory for companies that had gross revenues in the previous calendar year in excess of BRL78 million.

PIS/COFINS

In addition to the taxes levied on income, revenues earned by Brazilian companies are subject to PIS/COFINS at a combined rate of either 3.65% for companies under the cumulative regime or 9.25% for companies under the non-cumulative regime. The latter regime is generally mandatory for companies under APM and allows the calculation of non-cumulative credits for certain inputs, costs, and expenses incurred by the company to be offset against PIS/COFINS amounts that would otherwise be payable.

Withholding Tax

While dividends are exempt from income tax, payments of other income, capital gains and earnings to beneficiaries domiciled overseas are subject to withholding tax (WHT) at rates ranging from 0% to 25%. The remittance of fees for the charter of FPSO and other vessels used in E&P activities may be subject to a 0% tax rate if certain requirements are met. Except for dividends, payments made to beneficiaries domiciled in tax haven jurisdictions are subject to WHT at a rate of 25%, regardless of their nature.

Taxes on Importation of Services and Goods

Brazilian companies are also subject to taxes levied on the importation of services (WHT, PIS/COFINS-Importation, CIDE, ISS, and IOF) and goods (II, IPI, PIS/COFINS-Importation, ICMS, and AFRMM). 

Repetro-Sped

The importation of goods may benefit from Repetro-Sped – a special tax and customs regime applicable to the importation and local purchase of goods used in E&P activities. This regime is valid until 2040 and allows the local purchase and importation of certain goods expressly listed by Normative Instruction RFB No 1,781/2017, with the suspension or exemption of federal taxes otherwise levied on the temporary or definitive importation of those goods. Goods not listed may be imported under the temporary admission regime, provided a proportional payment of taxes is made.

Repetro-Sped also encompasses the so-called Repetro-Industrialização regime, which allows for both the importation and local acquisition of raw materials, intermediate products, and packaging materials for the manufacture of products used in E&P activities, with the suspension of federal taxes. Although the sale of the final manufactured product is exempt from State VAT (ICMS), its purchase by the E&P company is subject to ICMS at a rate of 3%.

Tax Reforms

Tax reforms are under discussion in the Brazilian Congress, and the resumption of taxation on dividends, which became exempt from income tax in 1996, is being proposed under Bill of Law No 1,087/2025.

The Brazilian tax reform related to consumption taxes (“Brazilian VAT Tax Reform”) was approved on 20 December 2023, through the Constitutional Amendment No 132/2023. The Reform will replace five taxes (PIS, COFINS, IPI, ICMS and ISS) with the dual Value-Added Tax (“Dual VAT”), which will consist of a broad-based and non-cumulative tax on goods and services, charged in the destination, with few tax rates and exceptions. Basically, Dual VAT will encompass:

• a Federal-level Goods & Services Contribution Tax (CBS) to replace the PIS/COFINS; and
• a State and Municipal-level Goods & Services Tax (IBS) to replace both ICMS and ISS.

IPI will be partially extinguished, remaining effective only in the Manaus Free Trade Zone.

Supplementary Law No 214/2025

On 16 January 2025, Supplementary Law No 214/2025 was approved, regulating key aspects of the tax reform on consumption taxes. This Law introduced the elements of the tax triggering events of CBS and IBS; the calculation basis of the taxes, and defined the taxpayers. As for the tax rates, according to the provisions set forth in the legislation, they will be established individually by each entity (the federal government, states, and municipalities) through a specific law, and the same rate must be applied to all transactions involving goods and services.

VAT Tax Reform

In addition, the Brazilian VAT Tax Reform introduced an Excise Tax (IS) levied on the production, extraction, sale, or import of goods and services that are harmful to human health or the environment, as also enacted by Supplementary Law No. 214/2025. Crude oil and natural gas were included in the list of goods subject to this levy. For crude oil, the maximum tax rate is 0.25%. Natural gas intended for use as an input in an industrial process and as a fuel for transportation purposes will be subject to a zero tax rate.

The transition period from the current to the new tax system shall take place over seven years – faster regarding the extinction of PIS/COFINS and IPI, and gradual in respect of ICMS and ISS. CBS shall be in force as of 2027, and IBS shall be in force as of 2033.

Petrobras

The most relevant national oil company with an operational role in Brazil is Petrobras.

Since the market’s opening, Petrobras has been conducting economic activities related to its corporate purpose in a free and competitive environment alongside other companies, in accordance with market conditions.

Preferential right

Since the Petroleum Law, Petrobras has not been granted special rights for E&P contract awards. However, the Pre-Salt Law gives Petrobras a preferential right to select areas for operation with a minimum 30% participation interest.

Decree No 9,041/2017 regulates this right, requiring Petrobras to express its interest in participating as an operator within 30 days of the CNPE resolution outlining technical and economic guidelines. If Petrobras exercises this right, the CNPE presents the blocks to the President, indicating Petrobras’ minimum participation.

If Petrobras opts not to exercise its right, the blocks are offered in a bid round, and Petrobras can bid on equal terms with other companies.

Withdrawal option

Furthermore, regarding Petrobras’s areas of interest, Decree No 9,041/2017 benefits the company with a “withdrawal option”, allowing Petrobras to refuse to enter into a PSC with another company or consortium declared as the winner of the bid round. The “withdrawal option” only applies in cases where the profit oil percentage offered to the federal government by another consortium is higher than the minimum percentage established in the tender protocol. In such cases, however, if the profit oil percentage offered by another consortium (winner) is equal to the minimum established in the tender protocol, Petrobras will be part of the consortium, jointly with the winning bidder.

If Petrobras is not integrated into the consortium, the winning bidder must appoint the operator and the participating interest of each party to the consortium, as a necessary condition for the approval of the bidding results by the ANP.

Local content requirements in Brazil correspond to a contractual obligation arising from the concession contract or the PSC, which may vary in accordance with the tender protocol and the applicable rules of each bid round.

Local Content Certificates

The contractor or concessionaire must demonstrate compliance with local content requirements by submitting local content certificates to the ANP, which will conduct an audit process in this regard. The certificates are issued by third-party certifying entities that the ANP accredits.

Upon assessing the certificates, if the ANP verifies that the concessionaire/contractor has not complied with the relevant local content requirements, a penalty may be applied, corresponding to the difference between the percentage achieved and the percentage committed to.

Removal of Local Content From Bid Criteria

Historically, local content obligations have been encompassed in E&P contracts in Brazil ever since the first bid round under the concession regime, as they were originally bid criteria. At the beginning of 2017, the federal government initiated several regulatory changes in the petroleum industry, including the removal of local content from the applicable bid criteria by means of CNPE Resolution 07/2017.

Percentages

To improve the attractiveness of the bid rounds, CNPE Resolution 07/2017 also reduced the minimum percentages of local content requirements that concessionaires or contractors of offshore blocks must comply with. This adjustment represented a significant reduction (50% on average) in local content requirements for the upcoming bid rounds at the time.

The mandatory local content percentages applicable to offshore exploratory blocks were recently adjusted by CNPE Resolution No 11/2023, as follows:

• 30% in the exploration phase; and
• 30% for well construction, 40% for the collection and offloading system and 25% for the stationary production unit, in the development phase.

Conduct Adjustment Agreement

ANP Resolution 848/2021 provided for the Conduct Adjustment Agreement (TAC), which allows local content infractions and/or fines to be replaced by new investments in national goods and services in relation to terminated contracts or already concluded contractual phases.

See 2.8 Other Key Terms: Upstream for a comprehensive analysis of the key terms of concessions and PSCs in Brazil, including the requirements for proceeding to development and production.

E&P Phases

Concessions and PSCs in Brazil typically provide for two distinct phases:

• the exploration phase, which comprises the appraisal of a discovery, if any; and
• the production phase, which includes the development stage.

During the exploration phase, concessionaires/contractors are obliged to perform all the activities contemplated by the minimum exploration programme, including conducting seismic works and drilling wells.

Concessionaires/contractors must provide the ANP with financial guarantees for the minimum exploration programme within the term established in the tender protocol.

Failure to comply with the minimum exploration programme at the end of the exploration phase may result in the lawful termination of the contract, without prejudice to the enforcement of the financial guarantees for exploration activities and the application of penalties.

After performance of the minimum exploration programme and within the expected term for the exploration phase, concessionaires/contractors may do the following, after providing written notice to the ANP:

• propose a discovery appraisal plan and relinquish the remaining area;
• inform the ANP about the commercial feasibility of the discovery (declaration of commerciality), initiating the production phase;
• retain the areas in which postponement of the declaration of commerciality is applicable; or
• fully relinquish the concession area.

The ANP must be informed of any discovery of oil and/or natural gas in the concession area within 72 hours. If the company decides to proceed with the appraisal of a discovery, it must submit a discovery appraisal plan for approval by the ANP.

Upon compliance with the discovery appraisal plan approved by the ANP, concessionaires/contractors may, at their sole discretion, submit the declaration of commerciality of the field, along with the final discovery appraisal report. Within 180 days of receiving notification of the approval of the final discovery appraisal report, concessionaires/contractors must also submit the development plan to the ANP, detailing the activities and investments to be made throughout their entire life cycle.

The production phase usually lasts up to 27 years for concession contracts, counted from the submission of the declaration of commerciality. A total contractual term of 35 years will apply for PSCs.

The field must be relinquished to the ANP at the end of the production phase, in compliance with the applicable laws and regulations and the best practices of the oil industry.

Liability

Concessionaires/contractors may carry out oil and gas E&P activities either individually or through a consortium with other companies. Under a consortium agreement, a lead company must be appointed to be the operator. The other consortium members will be jointly and severally liable before the ANP and the federal government for the obligations undertaken under the relevant contracts.

Decommissioning and Abandonment

Concessionaires must provide a decommissioning guarantee commencing from the start of production, covering the expected costs of decommissioning and abandonment. The amount can be adjusted if costs change. ANP Resolution 817/2020 modernised decommissioning regulations, and Resolution 854/2021 clarified obligations and deadlines for abandonment guarantees.

A financial guarantee or deed must be presented within 180 days of production start, matching the estimated decommissioning cost from the latest Annual Work Plan (PAT). Accepted guarantee types include letters of credit, insurance bonds, pledges, corporate guarantees, and provisioning funds. Self-insurance may also be permitted, subject to an enforceable agreement.

The ANP has discretion to approve, replace, or require adjustments to the guarantees if deemed inadequate.

Entitlement, Domestic Supply Requirements and Export Rights

Concessionaires and contractors are entitled to sell or dispose of the petroleum produced. As a rule, concession contracts and PSCs do not provide for restrictions on export rights.

The contracts provide for an exception in cases where the domestic supply of oil, natural gas or their by-products is at risk (an “emergency situation”), in which case, the ANP may determine that the concessionaire/contractor must limit its petroleum exports. The President of the Republic must declare an emergency situation.

Termination Events

Concession contracts and PSCs provide for several termination events, which are divided into three categories:

• lawful termination;
• bilateral termination (upon mutual agreement between the parties, without prejudice to the performance of the obligations thereunder) and unilateral termination (at any time during the production phase, giving the ANP at least 180 days’ prior notice); and
• termination for default:
1. failure of the concessionaire/contractor to perform the contractual obligations within the term established by the ANP;
2. the occurrence of a judicial or extra-judicial reorganisation; or
3. where the concessionaire/contractor’s economic and financial capacity to fully meet all contractual and regulatory obligations is not evidenced to the ANP.

Under any of the termination events set out above, the concessionaire/contractor will not be entitled to any reimbursement. Upon termination, the concessionaire/contractor will be liable for losses and damages arising from their default and termination, and will pay all applicable indemnifications and compensation as provided by Brazilian law and the relevant contracts.

Dispute Resolution

Both the concession contract and the PSC establish arbitration as the primary method of dispute resolution. The arbitration procedure will be administered by a recognised arbitration institution with a sound reputation, appointed by mutual agreement of the parties. If the parties do not reach an agreement as to the choice of arbitration institution, the ANP will indicate one of the following:

• the International Court of Arbitration of the International Chamber of Commerce;
• the London Court of International Arbitration; or
• the Hague Permanent Court of Arbitration.

The city of Rio de Janeiro, Brazil, will serve as the seat of the arbitration and the location where the arbitral award is rendered. On the merits, arbitrators will decide based on Brazilian laws, and the arbitration proceeding will be in Portuguese. It is worth noting that disputes already exist against the ANP, based on the arbitration clause of the relevant contracts.

The Petroleum and Pre-Salt Laws allow the assignment of concession contracts and PSCs if the assignee meets ANP’s requirements. ANP’s prior approval is needed for the assignment to take effect. This can be a direct transfer or an indirect one through corporate transactions, which also require approval from the ANP. The transaction may also be subject to approval by the Brazilian Antitrust Authority (CADE), if the gross revenues of the parties involved in the transaction (and the relevant economic groups) exceed certain thresholds established in Article 88 of Law 12,529/2011, as updated by Interministerial Ordinance No 994/2012.

There are no specific legal or regulatory restrictions on production rates.

Petrobras still dominates Brazil’s midstream sector, though its role has decreased in recent years due to efforts by antitrust authorities and the federal government to promote competition. Petrobras sold off many midstream and downstream assets, reducing its pipeline monopoly. There are no restrictions on private investments in refining, pipelines, transportation, or fuel distribution. Private investors must be authorised or registered with the ANP, which ensures compliance with existing laws and regulations when granting these approvals.

There are no legal national monopolies in Brazil in relation to downstream operations.

Refining Activities

Refining activities, including construction, the expansion of capacity and the operation of refineries, are subject to prior and express authorisation from the ANP, which is granted in a two-stage process:

• construction authorisation (construction, modification or expansion of capacity); and
• operation authorisation.

Companies interested in applying for refining-related authorisations must comply with the requirements of ANP Resolution 852/2021 (as amended by ANP Resolutions 881/2022 and 922/2023), ANP Technical Regulation No 1/2010 and relevant attachments. The applicant must be a company that exists and is incorporated in Brazil.

Upon completion of the works related to the construction authorisation, the applicant must formally request that the ANP inspect the facilities. To obtain the authorisations, the company must submit the relevant environmental licences, a specific fire safety certificate, and proof of ownership of the facilities or a lease agreement for a minimum period of five years to the ANP, along with other required documents and information.

Storage, Marketing and Distribution

The authorised refiner can only market refined products with distributors that are authorised to operate by the ANP. Such distributors must exclusively market the refined products with retail carriers (TRRs) and retailers of automotive fuels, liquefied petroleum gas (LPG) and aviation fuels.

Distribution is also subject to prior authorisation by the ANP following a process of staged application and the filing of documents as specified by ANP Resolution 950/2023.

The retail sale of automotive fuels may only be exercised by companies incorporated in Brazil that the ANP authorises to sell automotive fuels and that comply with the provisions set forth in ANP Resolution 948/2023.

In October 2023, the ANP issued ANP Resolution 960/2023, establishing new rules regarding the authorisation of operations of storage facilities for:

• automotive liquid fuels;
• aviation fuels;
• solvents;
• basic and finished lubricant oils;
• LPG;
• fuel oil;
• illuminating kerosene; and
• asphalts.

Any private investor that is eligible and capable of complying with the existing requirements may apply for authorisation or registration with the ANP.

The main transactional taxes applicable to midstream/downstream activities are PIS/COFINS, CIDE-Fuel and ICMS.

Comments regarding IRPJ and CSLL made in 2.4 Income or Profits Tax Regime: Upstream also apply to midstream/downstream activities.

Other Key Taxes

CIDE-Fuel

This is levied on the importation and trading of petroleum and its derivatives, natural gas and its derivatives, and ethyl alcohol fuel, currently available from producers, importers, and formulators at variable rates.

PIS/COFINS

The general aspects of this are detailed in 2.4 Income or Profits Tax Regime: Upstream. There are differentiated rates/regimes depending on the product and the specific activity segment of the taxpayer – currently, taxation is concentrated at the level of the producers, importers and/or distributors (the so-called monophasic regime). Importers, manufacturers or the ordering party of certain fuels may opt to use the so-called RECOB regime, which allows the payment of PIS/COFINS by ad-rem rates, multiplying the quantity of fuel acquired by specific values defined by tax legislation, as ruled by Complementary Law 192/2022 and 194/2022.

ICMS

Transactions involving fuels are typically subject to a “pre-payment” regime, where the tax substitute advances the ICMS due on subsequent transactions in the production chain (ICMS-ST) until the sale is made to the final consumer, based on statutory value-added margins. Complementary Law 192/2022, ICMS Agreement No 199/2022 and ICMS Agreement No 15/2023 regulated a new tax regime for anhydrous ethanol, gasoline, diesel, biodiesel and liquefied petroleum gas transactions (the so-called monophasic regime), in which the ICMS is due only once the fuel is in the production chain. In this regime, the ICMS is levied as the fuel exits the producer’s establishment or is in the customs clearance carried out by the importer.

Oil export tax

Provisional Measure 1,163/2023 established a levy of 9.2% on the oil export tax for crude oil (NCM 2709) exported between 1 March 2023 and 30 June 2023. This Provisional Measure is no longer effective and currently the export tax levies at a 0% rate on exportations of crude oil.

Exemptions

The Special Incentive Regime for Infrastructure Development (SIRID) may apply to projects related to the construction of infrastructure necessary for producing or processing natural gas and related pipelines. If so, such projects will be exempt from the PIS and COFINS normally levied on certain acquisitions used in pre-approved projects. Supplementary Law No. 214/2025 preserved this special regime, as outlined in Article 106, which provides for the suspension of IBS and CBS payments.

The Repetro-Sped regime does not apply to the importation or local purchase of assets or goods used in midstream/downstream operations. As a general rule, Repetro-Sped applies only to operations related to the exploration, development and production of oil and gas.

Reform Proposals

As mentioned in 2.4 Income or Profits Tax Regime: Upstream, tax reform proposals currently under discussion in the Brazilian Congress may also impact the taxes levied on midstream/downstream operations.

As per 3.2 Downstream Operations Run by a National Monopoly: Rights and Terms of Access, there are no legal national monopolies in Brazil regarding upstream and downstream activities. There are also no special rights for Petrobras (the national oil and gas company) or its subsidiaries in the Brazilian downstream sectors.

There are no mandatory local content requirements in connection with midstream/downstream activities in Brazil.

See 3.3 Issuing Midstream/Downstream Licences.

A cornerstone of the Brazilian Constitution is the protection of private property. Property rights in Brazil can be acquired through all means admitted under Brazilian civil law, and eminent domain rights and condemnation are permitted in certain circumstances as an exception to the general regime of private property protection.

Law 8,987/1995 (the Concessions Law) stipulates that only a public authority has the right of eminent domain. In Brazil, those rights translate into the power of certain public authorities to declare a property (including real estate) to be of “public interest” for the execution of a public service or work.

Condemnation in Brazil must be carried out directly by a public authority or by a private party utilising a delegation of powers, in which case the private party will be the one liable to pay any third parties the applicable financial compensation for the asset declared to be of public interest.

Expropriation of Property

Regarding the expropriation of real estate properties or the establishment of an administrative servitude on a private property for the performance of petroleum activities in particular, the ANP has the authority to conduct the relevant processes and to declare any assets (including real estate) necessary for the execution of a certain public activity to be of public interest, as provided in the Petroleum Law and Law 14,134/2021 (the “New Natural Gas Law”).

ANP Resolution 44/2011 sets out the applicable rules and requirements to be met by the parties interested in having a property declared by the ANP as being of public interest for the purposes of expropriation and/or the establishment of an administrative servitude.

For oil pipelines, ANP Resolution 52/2015 establishes the relevant rules for construction, expansion and operation. The ANP grants authorisations in two phases: construction authorisation and operation authorisation.

Regarding the gas industry, the Brazilian Constitution distinguishes between gas transportation and gas distribution services. The first is a federal monopoly regulated by the ANP, while the second is a state monopoly. At the federal level, the New Brazilian Gas Law grants the ANP the authority to issue authorisations for gas transportation activities, which include the construction, expansion, operation, and maintenance of gas transportation facilities. At the state level, most states have decided to perform gas distribution services through one or more concessionaires, which can be either public or privately held entities. Additionally, states have established regulatory agencies to oversee and regulate public service concessionaires.

Both the Petroleum Law and the New Natural Gas Law provide interested parties with rights to ANP-regulated third-party access to transportation pipelines and maritime terminals.

Third-party access to transportation pipelines is governed by ANP Resolution 11/16 (oil transportation pipelines) and ANP Resolution 35/12 (gas transportation pipelines).

There are no restrictions on product sales in the local Brazilian market.

ANP Resolution 959/2023 establishes the framework for exportation activities relating to biofuels and petroleum and their by-products, providing standardised authorisation requirements and administrative proceedings for both export and import licence applications.

The applicable ANP regulations, relevant requirements and available downstream licences in Brazil are addressed under 3.3 Issuing Midstream/Downstream Licences. The transfer of downstream licences typically requires prior approval from the ANP and is subject to the transferee’s ability to demonstrate their capacity to undertake the related downstream activity and comply with the applicable regulatory requirements.

BITs and the PCFI

Brazil has traditionally been less active in the foreign direct investment (FDI) system, having signed 25 bilateral investment treaties (BITs) between 1990 and 2014, but none have come into force. After 2015, Brazil signed more BITs and a Protocol of Co-operation with Argentina, Paraguay, and Uruguay. However, only the BITs with Angola, Mexico, and the PCFI with Uruguay are in force. None of these agreements include investor-state arbitration, so foreign investors must rely on arbitration clauses in their contracts for dispute resolution.

Creating a Climate for Foreign Investment

Over the years, Brazil has implemented crucial domestic changes to create a favourable climate for foreign investment by adopting rules in favour of neutral dispute resolution and international commercial transactions, including the enactment of pro-arbitration legislation, rules on the protection of property rights, and free enterprise. Brazil has also become a signatory to the Vienna Convention on Contracts for the International Sale of Goods.

Dispute resolution

In the petroleum industry, arbitration is the main dispute resolution mechanism in Brazil among public and private parties.

The adoption of arbitration by Brazilian law, particularly in Brazilian oil and gas legislation, and its acceptance by local courts are crucial aspects in attracting foreign investments.

Protection of property

Under Brazilian domestic substantive law, the protection of foreign investment is incorporated into the current legal and normative structure of Brazilian public administration. The Brazilian Constitution also guarantees the right to private ownership of property and free enterprise.

Brazil has not yet imposed unilateral sanctions against individuals or entities, and there is no specific legislation regulating this. However, Brazilian law and international treaties require compliance with multilateral sanctions databases and foreign requests to enforce sanctions. As a result, companies operating in Brazil may still be subject to foreign sanctions regimes, which could impose additional restrictions on their business activities, even if Brazilian law does not directly enforce them.

The Brazilian Constitution provides for environmental protection (Article 225), stating that every person has the right to an ecologically balanced environment. Federal authorities can pass general laws and regulations on environmental control, while states and municipalities can supplement federal legislation on issues of local interest. Moreover, the Brazilian Constitution ensures that all three administrative levels are responsible for the enforcement of environmental laws, so federal, state and municipal environmental agencies are all involved.

Complementary Law 140/2011 details the activities subject to environmental licensing by federal, state and municipal environmental protection agencies, and co-ordinates the enforcement power of those agencies.

Law 6,938/1981 implements the National Environmental Policy Act (NEPA) and details the environmental authorities at the federal, state and municipal levels. Among these authorities, it is worth mentioning the Federal Environmental Agency (IBAMA), the Federal Agency for Conservation Units (ICMBio), and state and municipal environmental agencies, which are responsible for the execution and enforcement of environmental laws at federal, state and municipal levels.

Environmental Liability

The Brazilian Constitution provides for environmental liability, which may be imposed against individuals or legal entities in three different fields, as follows.

Civil liability

This is tied to the concepts of pollution and polluter, and is strict, joint and several, and unlimited in liability. Strict liability means that no fault or wilful misconduct of the polluter needs to be evidenced in order to establish the obligation to repair or pay compensation for environmental damage. Joint and several liability means that each polluter may be called to indemnify or repair the entire damage, provided that the right of contribution is secured.

Administrative liability

This subjects the violator of a legal provision to administrative sanctions described in the Environmental Crimes Act (ECA), in Federal Decree No 6,514/08 and other laws and regulations. Environmental administrative liability is enforced by the competent federal, state or municipal environmental protection agency, through the application of auto-enforceable sanctions.

Environmental criminal liability

The ECA outlines criminal sanctions for activities harmful to the environment, with liability based on fault (negligence, imprudence, or intentional misconduct). Sanctions may include fines, community service, restrictions on rights, or imprisonment. Executive officers, directors, and managers can also face environmental criminal liability alongside companies.

Other Federal Laws and Regulations

Other laws and regulations are also important in the context of petroleum activities. At the federal level, the following should be highlighted:

• Federal Law 9,966/2000 and Federal Decree No 4,136/2002: pollution at sea, in line with the International Convention for the Prevention of Pollution from Ships (MARPOL) and other international conventions signed by Brazil regarding the matter;
• Federal Decree No 8,437/2015: activities that are subject to federal environmental licensing;
• Federal Law 9,985/2000 and Federal Decree No 4,340/2002: environmental compensation due from potentially polluting activities;
• MMA Ordinance No 422/2011: details the environmental licensing procedure for offshore petroleum activities, among others;
• Federal Law 14,850/2024 and CONAMA Resolution No 506/2024: provide for the National Air Quality Policy and respective standards; and
• CNPE Resolution No 8/2024: promotes the decarbonisation of oil and gas E&P activities.

Potentially polluting activities require environmental licences for upstream, midstream, or downstream projects, approving their location, installation, operation, and expansion. These licences impose obligations to mitigate or compensate for environmental impacts. Operating without proper licensing or failing to comply with licence conditions may lead to civil liability, administrative sanctions, and criminal liability. IBAMA conducts environmental licensing for offshore E&P activities for conventional resources, and onshore or offshore E&P activities for unconventional resources. State EPAs conduct proceedings for onshore E&P activities for conventional resources and, as a general rule, for midstream and downstream activities.

Offshore development is subject to environmental licensing procedures and compliance with several environmental laws on the management, control and reporting of incidents (see 5.1 Environmental Laws and Environmental Regulator(s) and 5.2 Environmental Obligations for a Major Hydrocarbon Project).

The ANP oversees E&P activities to ensure operational safety and prevent harm to people, the environment, and property. Key regulations include ANP Resolution 43/2007, which covers the Operational Safety Regime and the Technical Operational Safety Management System Regulation (SGSO Regulation), and ANP Resolution 41/2015, which addresses the Sub-sea Systems Operational Safety Regime and the Technical Regulation of the Sub-sea System Operational Safety Management System (SGSS). Companies must also implement the Occupational Health Control Programme (PCMSO) and the Environmental Risks Prevention Programme (PPRA), along with having an Internal Committee for Accident Prevention (CIPA) and Specialised Services in Health and Safety (SESMT) to ensure workplace safety.

The concessionaire/contractor is responsible for the decommissioning liabilities of the field before the ANP. ANP Resolution 817/2020 established obligations and deadlines for the decommissioning of oil and gas production systems, including the content of the decommissioning programme and the final decommissioning report. See Decommissioning and Abandonment in 2.8 Other Key Terms: Upstream for a more comprehensive analysis.

Brazil is a signatory to several international treaties, such as the Paris Agreement, which was ratified in 2017. In signing this agreement, Brazil undertook to reduce its greenhouse gas emissions to 37% below 2005 levels by 2025, and to 47% below by 2030, through attaining a 45% share of renewable energy in the energy mix, and increasing biofuel consumption, ethanol supply and biodiesel content in the diesel blend (among other means). Recently, in November 2024, Brazil submitted its new Nationally Determined Contribution (NDC), aiming to reduce greenhouse gas emissions to 59%-67% below 2005 levels by 2035.

Brazil enacted the National Policy on Climate Change Act (Law 12,187/2009), seeking to reduce GHG emissions, strengthen carbon capture initiatives and promote the recovery of degraded areas (among other objectives). Most recently, in December 2024, Brazil also enacted the Brazilian Emissions Trading System Act (Law 15,042/2024).

Brazil is also known for encouraging an increase in biofuels in its energy mix, having implemented several related mechanisms, such as a national biofuel policy called “RenovaBio”, the National Green Diesel Program (PNDV), and the National Program for Decarbonization of Natural Gas Producers and Importers and for Incentive to Biomethane (Law 14,993/2024).

Fracturing (“Fracking”)

In Brazil, exploration activities in the sedimentary basins have been carried out through conventional methods; however, a fracturing (“fracking”) process may be necessary to increase the flow area in the deposit, with the hydrocarbon lifted to the top of the well through induced fractures, considerably increasing the drainage area.

Brazil has attempted to promote the use of such techniques for evaluating the potential of gas production in its onshore basins, including Recôncavo, São Francisco, and Paraná.

Resolution 21/2014

The ANP has published Resolution 21/2014, which addresses operational safety concerns regarding the protection of people and the environment when using hydraulic fracturing techniques in unconventional reservoirs.

Recently, in May 2025, the Superior Court of Justice (STJ) initiated a 30-day public consultation to gather contributions regarding the potential use of the fracking technique for the exploration of unconventional oil and gas resources, such as shale. Individuals and representatives of organisations are invited to participate, providing their insights on the subject.

Brazil is one of the countries making the most progress in implementing actions towards the energy transition and currently holds 12th place in the Energy Transition Index (ETI). Brazil has historically been a country with a diversified energy mix and an expressive production of energy from renewable sources (around 48.4% of the energy mix) and now seeks to strengthen the country’s position in the energy transition by fostering new initiatives ranging from regulatory updates to new legal frameworks to address the new energy sources and technologies.

Among such initiatives is the National Hydrogen Program, created by CNPE in 2021 and ratified by Law 14,948/2024 (the so-called Legal Framework of Low-Carbon Hydrogen), composed of strategic guidelines and policies to boost the hydrogen market and industry. The Legal Framework of Low-Carbon Hydrogen establishes mechanisms for integrating low-carbon hydrogen into the national energy sector and provides tax incentives to encourage its use (Rehidro).

Moreover, Law No 14.993/2024 (the Fuel of the Future Law), recently enacted in Brazil, constitutes a comprehensive legislative framework aimed at fostering sustainable, low-carbon mobility while enhancing the nation’s energy transition. It introduces a multifaceted approach to emissions reduction by integrating existing policies, such as RenovaBio and Proconve, and establishing robust programmes including the National Green Diesel Programme (PNDV) and the National Programme for Sustainable Aviation Fuel (ProBioQAV). The Law mandates progressive reductions in greenhouse gas emissions across various transportation sectors, with a particular emphasis on aviation and road transport. Furthermore, it advances regulatory mechanisms for Carbon Capture, Utilisation and Storage (CCUS), underscoring the nation’s commitment to environmental stewardship.

The Brazilian Congress is currently deliberating a specific legal framework for CCUS activities, included in the 2024 priority legislative agenda. In parallel, the ANP concluded its studies in April 2024, resulting in a technical opinion that outlines potential regulatory mechanisms and the departments involved in future CCUS regulation. While CCUS projects are already underway, a defined legal framework would enhance legal certainty and attract further investment. Brazil also enacted its first offshore power generation legislation with Decree 10,946/2022, further regulated by MME Ordinance No. 52/2022 and MME/MMA Joint Ordinance No 03/2022. Additionally, to reduce transport-related GHG emissions, the government launched the Fuel of the Future Programme in 2021, promoting low-carbon fuels through a committee involving 15 government entities.

Brazil has the potential to harness the advantages of integrating new technologies for the energy transition with the use of existing assets in the O&G sector, aligning with the current focus of several players in the Brazilian market who seek to reduce greenhouse gas emissions from their operations.

A notable example is the inclusion in PPSA’s 2024–2028 strategic plan of a specific goal to promote decarbonisation actions in the pre-salt blocks, which account for nearly 80% of the total national oil production. Among the projects already in place in the pre-salt is the use of CCUS technology by Petrobras, which is the largest in operation in the world according to the volume reinjected each year, and also the pioneer project in ultra-deep waters.

The number of CCUS projects has grown in recent years. At the end of 2021, the projects under development represented a capture capacity of 111 million tonnes of per year (Mtpa) (an increase of 48% in comparison with 2020). The investments in CCUS are expected to range from BRL2 billion to BRL4.5 billion annually by 2050.

The execution of offshore petroleum E&P activities and the generation of offshore wind power also have synergies in their implementation, development, and even decommissioning. Furthermore, Brazil has a robust offshore industry linked to O&G production, as well as the technological and operational expertise of several players to enhance the exploitation of wind potential, combined with the electrification of O&G platforms and the production of hydrogen. Although the legal framework is still under development, recent progress has been marked by the enactment of Law 15.097/2025, which provides a foundational regulatory structure for the development of offshore wind projects in Brazil. Currently, there are around 230 GW of offshore wind projects with an environmental licensing process underway in the country. This is an indicator of the market’s keen interest in the subject.

Other substantial investments are being forecasted, in particular for hydrogen production in Brazil. According to FGV Energia and EPE, more than USD30 billion will be invested in low-carbon hydrogen production in the country over the coming years. There are currently at least 15 green hydrogen pilot plants in the country, most of them based on the electrolysis of water for the production of hydrogen. The majority of these projects are concentrated in the northeast region (especially in Ceará and Pernambuco), due to the vast availability of clean energy sources (wind and solar) and the fact that their geographical location offers a shorter route for export to Europe. According to EPE, Brazil has the potential to produce up to 1.8 gigatonnes of hydrogen per year, of which only 18 megatonnes would come from onshore renewable sources. This indicates that most of Brazil’s hydrogen will be produced offshore and will use natural gas transportation pipelines, reinforcing the aforementioned synergy with the O&G sector.

Sustainable aviation fuel (SAF), which can be produced using oilseeds, solid urban waste, and ethanol, has gained prominence as a possible substitute for aviation kerosene, as it emits 80% less CO₂. In 2016, the International Civil Aviation Organisation created the Carbon Offsetting and Reduction Scheme for International Aviation (“Corsia”), through which various countries (including Brazil) are committed to reaching net-zero emissions in the aviation sector by 2050, with targets for the use of SAF starting in 2027.

In line with the energy transition global concern after the 21st Paris Conference of the United Nations Framework Convention on Climate Change, Brazil set forth its Nationally Determined Contribution (NDC) to reduce GHG emissions:

• to 37% below the 2005 levels, until 2025; and
• to 50% below the 2005 levels, until 2030.

Unlike most countries, the GHG emissions in Brazil are not deeply connected to energy production but are rather predominantly related to agriculture and land use change (deforestation), amounting to around 73% of the country’s total GHG emissions. The decarbonisation of these sectors requires specific mitigating measures, such as reducing illegal deforestation, which have no direct or significant impact on the traditional O&G development in Brazil.

This particular conjuncture allows Brazil to pursue and meet its NDC while maintaining O&G production. Moreover, the high productivity of the Brazilian pre-salt enables operations in Brazil to have a carbon footprint below the world average. For example, according to EPE, the pre-salt fields (accounting for 80% of national production) have a carbon footprint of less than 10.0 kg CO₂e/boe, while the global average is 22.0kg CO₂e/boe.

In 2023, more than USD34.8 billion was invested in the energy transition in Brazil, and, based on forecasts from the Brazilian Ministry of Civil Affairs, the same value is expected to be invested by 2028. Investments in the O&G sector are expected to exceed USD100 billion over the next five years, according to the ANP. The traditional O&G sector and energy transition initiatives offer a wide range of opportunities for continued development in Brazil.

No particular unconventional interests in upstream have been noted.

For more on upstream, see 2. Private Investment in Hydrocarbons: Upstream.

The typical structures for LNG projects in Brazil are as follows:

• a structure where the imported LNG is regasified at a floating, storage and regasification unit, which is connected to the transport pipeline or power plant through pipelines (Offshore Regasification Terminal); or
• a structure where the imported LNG is regasified at a regasification plant within a certain industrial site, in which case a special LNG pipeline may connect the storage facilities to the regasification plant (Onshore Regasification Terminal).

Both the Offshore Regasification Terminal and the Onshore Regasification Terminal are classified as an LNG Terminal, pursuant to the New Natural Gas Law and ANP Resolution 50/2011.

Authorisation

The construction and operation of an LNG terminal require several key permits, including environmental, port and maritime, and LNG and gas regulatory authorisations. ANP Resolution 52/2015 governs the authorisation process, which is divided into two phases: construction and operation. The ANP grants these authorisations based on detailed technical information that must comply with specific requirements set by the ANP and other relevant technical bodies. In addition to securing environmental, port, and maritime permits, interested parties must also obtain separate authorisation and LNG Self-Importer Registration under ANP Resolution 51/2011 to import LNG. The application process involves submitting corporate documents and a comprehensive project presentation detailing all facilities, pipelines, and gas specifications.

Transfer of Rights (ToR)

To increase the financial capacity of Petrobras for exploring and producing pre-salt reserves, Law 12,276/2010 introduced the Transfer of Rights (ToR), which defined a special capitalisation of Petrobras, and assigned Petrobras (upon consideration and through direct contracting) the right to produce up to five billion BOE in certain pre-salt areas.

As consideration, Petrobras paid BRL74.8 million for the ToR, and the company’s capitalisation process amounted to BRL120 billion (representing the largest capitalisation in world history at the time). As mandated by Law 12,276/2010, the federal government and Petrobras entered into a special E&P contract to govern the ToR.

ToR Bid Round

In addition to Petrobras’s right to produce five billion BOE, studies estimate an extra six to 15 billion BOE in the ToR area (“ToR Surplus”). To attract private investment and raise federal funds, the ANP held the ToR Bid Round in November 2019 under the production sharing regime, offering development rights in the Atapu, Búzios, Itapu, and Sépia areas. Petrobras acquired 100% of Itapu, while a consortium of Petrobras (90%), CNOOC (5%), and CNODC (5%) won Búzios. No bids were received for Atapu or Sépia, but the government raised around BRL70 billion in signature bonuses plus future oil profits.

ToR Bid Round 2

In December 2021, both the unawarded areas of Atapu and Sépia were acquired in ToR Bid Round 2, which amounted to BRL11.14 billion in signature bonuses. The Atapu area was acquired by a consortium formed by Petrobras (52.5%), TotalEnergies EP (22.5%), and Shell Brasil (25%), with a 31.68% stake in the oil profit. The Sépia area was acquired by a consortium composed of Petrobras (30%), QP Brasil (21%), Petronas (21%) and TotalEnergies EP (28%), with 37.43% profit oil. Petrobras exercised its preferential rights to be the operator in the areas.

Over the past year in Brazil, the main changes in the oil and gas laws and regulations were as follows:

• enactment of Law 14.948/2024, establishing the legal framework for low-carbon hydrogen; and
• enactment of Law 15.103/2025, establishing the Energy Transition Acceleration Program (Paten), which introduces mechanisms to promote investments in renewable energy, enhance energy efficiency, and facilitate the development of low-carbon technologies.