Contrary to other jurisdictions, such as the United States, in Mexico, the state maintains ownership of hydrocarbons found in the subsoil. This distinctive framework means that upstream participants, including the state-owned Pemex, can’t obtain ownership or provide security interests in these subsoil hydrocarbons.

Under License Agreements and Production-Sharing Contracts, the transfer of ownership for the extracted hydrocarbons only takes place after the required considerations, in cash or in kind, are duly provided to the state. This is detailed in the Hydrocarbons Law and the Hydrocarbons Revenue Law.

Despite these unique characteristics of the Mexican legal framework, companies have found ways to structure reserve-based lending agreements. Mexico’s legal system permits private entities to disclose upstream agreements they have entered into with the Mexican state, along with their anticipated benefits, as long as it is explicitly acknowledged that the resources in the subsoil will remain under Mexican ownership.

Federal agencies are chiefly responsible for the regulation of oil and gas (O&G) activities in Mexico. These agencies operate under various legal frameworks, including the Federal Constitution, the Hydrocarbons Law, the Hydrocarbons Revenue Law, the Coordinated Energy Regulatory Bodies Law, and the Law of the National Agency for Industrial Safety and Environmental Protection of the Hydrocarbons Sector (ASEA). Additional federal regulations, rules and guidelines also come into play.

The primary federal agencies governing O&G activities include the following.

• Ministry of Energy (SENER) – tasked with setting energy policy and issuing permits for import/export and refining activities.

• Ministry of Finance– oversees and regulates the state’s oil revenues and stipulates the economic conditions of exploration and production contracts (“E&P Contracts”).
• National Hydrocarbons Commission (CNH) – manages upstream regulation and serves as the counterpart to upstream operators. This includes conducting bidding processes and supervising the satisfactory execution of E&P contracts.
• Energy Regulatory Commission (CRE) – regulates technical and economic aspects of midstream and downstream activities, grants and supervises permits, and imposes sanctions, as well as regulating the entire power sector chain.
• Agency for Industrial Safety and Environmental Protection of the Hydrocarbons Sector– regulates and oversees industrial and operational safety and environmental protection within the hydrocarbons sector.
• Ministry of Economy– regulates and supervises technology transfers and local content obligations.
• Mexican Petroleum Fund– responsible for receiving, managing and distributing income from E&P activities.

Mexico is home to two state-owned companies, known as State Productive Enterprises (SPEs), that are actively involved in the O&G industry.

• Petróleos Mexicanos is the most important entity, having a significant role in upstream, midstream and downstream activities. For almost 80 years, Mexico operated under a state-monopolistic scheme where Pemex was the sole operator. However, following the 2013 constitutional energy reform, the O&G sectors opened up to private participation, including both Mexican and foreign investors. Pemex retained certain exploration and production rights through a selection process known as “Round Zero”, while the rest were offered in international public tenders. Pemex also participated in these other bids, competing with and partnering with international oil companies (IOCs), and secured 14 contracts.
• Comisión Federal de Electricidad (CFE) also plays a role in the industry, primarily marketing natural gas and promoting new pipeline projects, although its principal purpose is the generation, transmission and distribution of electric energy. However, unlike Pemex, CFE does not have upstream and refining capacity.

Over the years, Pemex’s dominance in the industry has seen various transformations. For instance, before 2022, the only Floating, Production, Storage, and Offloading (FPSO) in Mexico was the Yuum K’ak’ Naab, operated exclusively by Pemex. However, industry expansion has since necessitated private additional FPSOs.

Another crucial development was the creation of the National Integrated Storage and Transport System, an integrated system incorporating all natural gas transportation pipelines previously owned by Pemex. Following the 2013 energy reform, these pipelines were transferred to the National Natural Gas Control Center, an independent system operator.

However, the energy sector underwent another significant shift with the arrival of President Andrés Manuel Lopez Obrador (AMLO) in 2018. The AMLO administration prioritised strengthening SPEs, focusing on state investment in O&G and curtailing private companies’ participation. This policy shift has spurred debates and important litigation on the role of private investment and competition versus a state-centric approach.

Mexico’s O&G industry is subject to extensive regulation. Unlike in other jurisdictions where property and contract law govern most activities and relationships, in Mexico, all activities throughout the value chain require governmental authorisation for upstream producers or permits for midstream and downstream operations. Contractors and permit holders are bound by various legal and regulatory obligations outlined in laws, regulations, administrative provisions and directives issued by the Federal Congress and administrative agencies such as the CNH and the CRE.

The constitutional framework implemented in 2013 established fundamental principles including free competition between SPEs and private companies (both foreign and domestic), consumer protection, empowerment of regulatory bodies, transparency and accountability. Secondary legislation and regulations were developed to align with the constitutional amendments.

However, the current federal administration led by AMLO has taken actions that undermine free competition and instead favour and privilege the SPEs in the O&G and power industries. These actions include new regulatory rules, suspension of permits for private operators, and other de facto measures by existing governmental agencies under the executive branch.

Furthermore, in 2021, the Mexican Congress passed two bills proposed by AMLO amending the Hydrocarbons Law. Private companies submitted judicial challenges, arguing that these amendments contravene the constitutional framework. The Mexican Supreme Court has ruled that one of the amendments, which uplifted certain asymmetric regulations imposed on Pemex, is unconstitutional. The final ruling on the second amendment, which addresses the temporary and definitive suspension of permits and state intervention in facilities, is still pending.

Also, despite the administrative, technical, and operational autonomy granted to the CNH and the CRE, these agencies have deviated since 2018 from open-market principles outlined in the regulatory framework. This has resulted in significant permitting delays and, in some cases, hindered private participants from efficiently developing energy activities and infrastructure projects. Affected parties have resorted to seeking legal remedies, either domestically or internationally, and engaging in litigation or arbitration to protect their assets, rights, or obtain reasonably accessible permits and authorisations under the applicable law.

Litigation and arbitration has been based on key principles of the legal framework, including violations of free competition, contravention of superior rules (such as the Federal Constitution), lack of authority or encroachment on other regulators’ jurisdiction, acquired rights, legitimate expectations, environmental concerns, energy sufficiency and violations of international investment protection treaties.

Other principles applicable to O&G include open and non-discriminatory access to midstream facilities, standard quality specifications for fuels, restrictions on vertically integrated entities and cross-ownership, statutory minimum stock requirements for refined products and natural gas, and asymmetric measures imposed on Pemex to limit its dominant market power and ensure a level playing field for private participants.

Private investors in Mexico’s upstream sector obtain the right to explore, develop and produce hydrocarbons through entitlements or international public tenders. Entitlements are applicable only to SPEs such as Pemex, while international public tenders are conducted by the Mexican government to award E&P Contracts. The specific contractual nature of each contract depends on the field and may range from revenue or production sharing to license agreements.

It is important to note the distinction between a concession-based framework and a contract-based framework. In a concession, rights are granted to the concessionaire for providing a public service or exploiting public domain property. In the contract model, the state retains ownership of the hydrocarbons, and the E&P activities are contracted with SPEs and/or private parties.

Mexico’s legal framework ensures that SPEs, such as Pemex, do not have preferential treatment in bidding processes. The regulation provides equal treatment for both SPEs and private companies in terms of payment considerations, authorisations, relinquishment of contractual areas, and other terms of the E&P Contracts.

However, some private companies have raised concerns about the fair and equitable treatment given by Mexican authorities, suggesting preferential treatment towards SPEs. An example is the Zama field, where Talos Energy and its consortium partners discovered that their reservoir extended into an adjacent area assigned to Pemex. A unitisation process was initiated by the government to determine the rights and responsibilities of each party, but an agreement between Pemex and Talos Energy could not be reached. Talos Energy subsequently submitted a Notice of Intent of Arbitration under Chapter 14 of the United States-Mexico-Canada Agreement.

The international public tenders conducted between 2015 and 2018 resulted in various outcomes.

• The Mexican State generated revenue through royalties, taxes, bonuses and other fees associated with the extracted oil and gas. As of March 2023, cumulative state revenue stands at USD2,801 million, while the total accumulated investment until May 2023 amounts to USD12,940 million.
• Pemex successfully formed strategic alliances with IOCs through farm-out agreements.
• Multiple discoveries have been made by Pemex and private parties, both inland and offshore. Currently, there are 34 E&P Contracts in the development phase, resulting in the production of 204.4 million barrels per day of petroleum and 229.3 million cubic meters of natural gas.
• 73 companies from 20 countries have executed E&P Contracts.
• The growth of the national industry is facilitated by local content requirements, which mandate that E&P activities reach an average of 35% local content by 2025.
• The current regulatory framework includes enhanced environmental protection measures and social impact considerations compared to regulations in force before 2013.
• Equal treatment is ensured for both SPEs and private entities under the regulations.
• The autonomy of the CNH has been strengthened, resulting in unprecedented fines imposed on Pemex for breaching regulatory and contractual obligations, such as gas flaring limitations.
• In December 2018, at the request of the SENER, the CNH cancelled two international bidding processes that initially offered 37 E&P Contracts for conventional fields and nine E&P Contracts for unconventional fields requiring fracking technology. The cancellation occurred despite an estimated projected investment of USD2,309 million if all the fields were awarded.

While fracking is not prohibited by law, the CNH has not authorised any projects utilising this technology. Additionally, President AMLO has publicly stated that no fracking projects will be allowed during his administration.

Private investors obtain upstream licences through international bidding processes conducted by the CNH. These bidding processes are open to both national and international bidders and aim to ensure transparency and competition in the allocation of E&P Contracts. The process of obtaining an upstream license involves several steps:

• Announcement of the bid – the CNH announces the bidding process, providing information on the tendered areas, participation requirements, model contracts, and a timeline for the process.
• Registration and pre-qualification – interested companies must register and meet the pre-qualification requirements set by the CNH. These requirements typically include financial capacity, technical expertise, prior experience in E&P, and compliance with legal and regulatory obligations. The CNH evaluates the credentials of the bidders and may request additional information or clarifications.
• Data room access – registered participants are required to pay a fee to access the data room, which contains geological, geophysical, engineering and legal data related to the available areas.
• Submission of bids – bidders submit their proposals, including a binding offer and an execution guarantee in the form of a letter of credit. The bids are evaluated based on technical, economic and legal aspects.
• Awarding of E&P contracts – the CNH awards the E&P Contracts to the highest-ranking bids that meet all the criteria outlined in the bidding process. Contracts are executed with the winning bidders, granting them the right and obligation to undertake E&P activities in the specified areas.

The qualifications required for obtaining an upstream licence may vary depending on the complexity of the areas and the specific bidding process. Generally, bidders are expected to demonstrate financial capacity, technical expertise and a track record of other successful E&P projects. They must have access to funding sources and demonstrate the ability to meet financial obligations and investment commitments.

Separate major permits may be required for the conduct of operations, such as environmental permits, drilling permits and permits for the use of natural resources. These permits ensure compliance with environmental regulations and other legal requirements. The operator must also obtain multiple approvals from the CNH throughout the contract’s duration to carry out E&P activities.

Regarding significant changes in the regulatory approach, it is noteworthy that in December 2018, the CNH suspended future E&P tenders indefinitely. This suspension did not affect existing E&P Contracts but has created challenges for E&P operators in securing key permits, such as marketing and export permits.

Under upstream licenses in Mexico, the government receives various forms of financial compensation from the contractors. The specific fiscal terms depend on the type of contract, which can include royalties, profit share, bonuses, rentals and development obligations. Crude oil and natural gas may have separate fiscal terms.

What follows are the typical fiscal terms and rates under current contracts.

• Royalties – royalties are payments made to the government based on the volume or value of hydrocarbons produced. The royalty rates vary depending on the contract and can be calculated using sliding scales or fixed rates. For example, royalty rates for crude oil can range from 1% to 10% based on the volume produced, while royalty rates for natural gas can range from 2.5% to 10% based on the volume produced.
• Profit share – in profit-sharing contracts, the government receives a share of the profits generated from hydrocarbon production. The profit share can be calculated using a sliding scale or formula that takes into account factors such as oil prices and production costs. Payment can be in the form of hydrocarbons or in cash. The government’s share typically increases as the profitability of the project increases.
• Bonuses – bonuses are upfront payments made by the contractors during the bidding process to secure the contract. The amount of the bonuses varies depending on the specific bidding round and the value of the contract area.
• Rentals – rentals are periodic payments made by the contractors for the use of the contract area. The rental rates are typically fixed and are paid annually or at regular intervals throughout the contract’s duration.
• Development obligations – contractors are often required to meet specific development obligations, such as investing in exploration, drilling wells and implementing production plans. Failure to meet these obligations may result in penalties or the termination of the contract.

It is important to note that recent government trends have shown a shift towards increasing the state’s participation and benefits in upstream activities. The current administration has emphasised the role of state-owned companies and has implemented measures to strengthen their position in the industry. This has led to some changes in the fiscal terms and regulatory approach for newly issued contracts, with a focus on maximising state revenue and ensuring the government’s participation in the value generated from hydrocarbon production.

In addition to the royalties and fees mentioned in 2.3 Typical Fiscal Terms: Upstream, companies engaged in upstream operations in Mexico are subject to various taxes at the federal and state levels. The key taxes applicable to upstream operations include the following:

• Income tax – upstream companies are subject to income tax on their profits. The federal income tax rate is currently up to 30%, but deductions and applicable tax incentives may be available to reduce the taxable income.
• Value-added tax (VAT) – the standard VAT rate in Mexico is 16%. However, some transactions strictly related to upstream activities, such as the exploration and production of hydrocarbons, are taxed at a 0% rate.
• Special tax for upstream activities – this tax is a flat fee per square kilometre of the awarded E&P area. The fee varies depending on the phase of the project, with different rates for exploration and development activities. As of now, the fee is MXN2,177.64 per square kilometre for the exploration phase and MXN8,710.69 for the development phase.
• Governmental fees – upstream operators are required to pay fees for the issuance and maintenance of permits and E&P authorisations. The specific fees vary depending on the type of authorisation and the activities being conducted.

In addition to these federal taxes, it is important to note that there may be local taxes imposed by Mexican states and municipalities. The local tax regimes can vary across different regions, and companies operating in specific areas may be subject to such additional taxes or fees at the local level.

Please note that Mexico does not impose currency exchange restrictions or limitations on warranty or currency transfers.

At the federal level, Pemex, as the national oil company of Mexico, has certain special rights in connection with upstream licenses. These rights include the folllowing:

• Entitlements – Pemex was granted specific E&P rights through the entitlements process during the Round Zero allocation. These entitlements provide Pemex with the exclusive right to explore and produce hydrocarbons in certain designated areas.
• Exceptional grant of entitlements – SENER has the authority to exceptionally grant new entitlements to Pemex or any other State Productive Enterprise if it is deemed to be in the best interest of the state. This can be done to ensure hydrocarbon production and supply guarantees.
• Right of first refusal – in certain circumstances, Pemex may have a right of first refusal to participate in upstream opportunities before they are opened to private investors. This allows Pemex to maintain a level of priority in the allocation of new projects.

It is important to note that while Pemex has certain special rights, the Mexican government has implemented reforms to open up the upstream sector to private investment. As a result, Pemex now competes with private companies in bidding rounds for the allocation of new E&P contracts.

Local content requirements for upstream operations in Mexico are primarily regulated at the federal level. The local content requirements aim to promote the development of the national industry, create job opportunities and enhance technology transfer. The specific requirements for each E&P Contract may vary, but there is an overall goal to reach an average local content of 35% by 2025, excluding deep and ultra-deepwater activities, which have a lower target of 8% by 2025.

The Ministry of Economy is responsible for monitoring and evaluating compliance with local content requirements. Contractors are required to submit yearly reports on their local content performance, which are reviewed by the Ministry. Failure to meet the local content requirements may result in fines and/or liquidated damages, as specified in the terms and conditions of each E&P Contract.

It is important to note that there are currently no specific state and municipal requirements for the use of local goods and services, local employment, or training programmes in upstream operations. However, the federal government’s local content requirements apply across all regions of Mexico.

In Mexico, the execution of E&P Contracts obliges the operator not only to the right but also the responsibility to carry out E&P activities, guided by rigorous regulations encompassing energy, environmental and social spheres.

To embark on E&P activities, the operator must secure numerous approvals from the CNH, such as:

• appraisal and development plans;
• surface exploration studies;
• drilling operations;
• gas flaring;
• suspension of E&P activities;
• modifications in contractual terms; and
• change of control or transfer of operations.

The CNH Guidelines that Regulate the Exploration and Development Plans for the Extraction of Hydrocarbons provides a detailed framework for the approval of appraisal and development plans. Under these guidelines, E&P contractors are mandated to present comprehensive plans elucidating proposed activities, schedules and technical details for exploration and production. This includes specifics on drilling sites, production methods, necessary infrastructure and environmental impact assessments.

Each proposed plan, complete with corresponding government fees for analysis, must be submitted to the CNH for evaluation. Once received, CNH has a 15-business-day window to review and request remediation or clarification for any missing data or non-compliance with regulations. This period can be extended by another 15 days, with a potential for an additional eight days if necessary. A full approval process can take up to 85 business days if the proposed plan satisfies all laws, regulations and technical standards. Any alterations to the plan require approval via a simplified process.

In terms of dispute resolution, traditionally, the non-authorisation of plans by the CNH can be contested only via an indirect amparo proceeding. However, the Mexican Supreme Court in August 2020 ruled that a nullity trial (which is the standard recourse for most administrative actions) would be applicable to these type of claims.

Land-use agreement negotiation and finalisation with private owners is an additional step for onshore operators, potentially entailing a profit-sharing arrangement once oil production is commercially viable. These operators must follow a specific procedure laid out in the Hydrocarbons Law and its regulations, using the model agreement provided by the SENER. Federal court validation is required for any agreements reached between the operator and landowners to grant res judicata status to the agreement.

Moreover, before issuing entitlements or initiating a public bidding process, SENER, in collaboration with the Ministry of the Interior, conducts social impact assessments for the proposed development area and undertakes consultation procedures to respect the rights and interests of communities and indigenous peoples. This practice was evidenced in 2017 when two potential Contract Areas in Chiapas were excluded from a bidding process due to the failure of the authorities to obtain free, prior and informed consent from the indigenous communities.

Although amparos have been initiated by indigenous communities and fishermen against certain E&P Contracts, to date, they have largely been ruled in favour of maintaining the contracts.

Among the 108 existing E&P Contracts:

• 74 are licence contracts, empowering contractors to undertake petroleum activities within a contract area, such as seismic surveys, drilling and extraction. The obligations under these contracts extend to carrying out specified investments and paying due royalties, taxes and fees to the Mexican government. The specific terms and conditions, such as the minimum work programme, periods, terms warranties, insurances and mechanisms for contract area relinquishment, may vary depending on the contract area; and
• 34 are shared production contracts. Under these, contractors are entitled to recover costs associated with seismic surveys, drilling, equipment and other operational expenses. Once these costs are recuperated, profits are divided between the state and the contractor based on a pre-determined formula. As with licence contracts, terms and conditions can vary depending on the contract area.

Additionally, three of these contracts are farm-outs, enabling Pemex to collaborate with another contractor to conduct petroleum activities within one of Pemex’s entitlements. The primary terms and conditions of farm-out contracts centre around the interest portion being transferred from Pemex to the new contractor. Just like other E&P Contracts, these key terms and conditions can vary from one farm-out to another.

It is critical to note that E&P Contracts’ terms and conditions are non-negotiable. Successful bidders are expected to execute the model contract presented in the bidding rules without changes. However, participants may put forward questions and suggestions concerning the terms and conditions during the bidding process.

E&P Contracts span between 25 and 40 years, with potential extensions based on the contract area, extending no more than a total of 50 years. These contracts are segmented into various stages: (i) the startup transition stage, (ii) the exploration phase, (iii) the development phase, and (iv) the relinquishment of the contract area.

The Hydrocarbons Law and E&P Contracts stipulate general grounds for termination, including: (i) expiration of the term, (ii) contractor relinquishment, (iii) force majeure, (iv) administrative and contractual rescission, (v) expropriation, and (vi) indirect expropriation.

Disputes arising from E&P Contracts may be addressed via conciliation (not applicable to administrative recession), arbitration (under the UNCITRAL rules), or litigation before Mexican Federal Courts.

Moreover, some companies benefit from investment protection treaties. Mexico has ratified more than thirty Bilateral Investment Treaties and several international agreements with the intent to deter any arbitrary or unfair alterations to the investment environment.

Transferring interests in an E&P Contract requires the authorisation of the CNH, except for transfers between companies already within the E&P Contract consortium and where there is no change in operational management or control. In such cases, a notice to the CNH must be given within 30 days of the transaction.

A CNH prior authorisation is needed when there is a change in operational management or control. Changes in the corporate structure that do not result in a change of control merely need to be notified to the CNH and do not require prior approval.

The authorisation process is delineated in the Guidelines for Assignment, Corporate Changes, and Liens. These guidelines lay out a two-step process.

• The first step involves a request to the CNH for confirmation that the proposed assignee possesses the necessary legal and technical capabilities to become a contractor under the E&P Contract. The prospective contractor must satisfy all minimum legal and technical requirements outlined in the bidding guidelines applicable to the process through which the relevant E&P Contract was awarded.
• Before responding, the CNH will obtain and take into account the prior written opinions of the Financial Intelligence Unit of the Ministry of Finance to prevent illegal resource utilisation in the activities of the corresponding E&P Contract and the ASEA opinion regarding the industrial and operational safety and environmental protection plans applicable to the upstream sector. The CNH has a 30 business-day window to confirm whether the proposed contractor fulfills the requirements.
• If the CNH affirms that the proposed contractor meets all requirements, a joint petition by the contractor and the proposed contractor must be submitted to the CNH, formally requesting the assignment authorisation. The CNH will consider SENER’s opinion in its decision-making process. The CNH has 30 business days to grant the authorisation. If the CNH does not respond within this period, the request will be deemed authorised. If the CNH denies the request, the involved parties may appeal the decision within the CNH.

Following the authorisation, the proposed contractor and the contractor must complete all required legal documents to effectively assign the participation within 20 business days. The applicable E&P Contract must be amended to reflect the assignment. Please note that governmental fees are incurred for the CNH’s review of the assignment request.

In certain circumstances where certain thresholds are met, pre-transaction approval from the Federal Economic Competition Commission (COFECE) may be necessary.

Currently there are no restrictions on production rates.        

In Mexico, midstream and downstream operations in the hydrocarbons sector are open to private investment. This includes activities such as gathering and transportation pipelines, processing and fractionation systems, storage and terminal facilities, refineries and petrochemical facilities, along with wholesale and retail marketing. There is no government or private monopoly in these sectors.

Investments in these sectors are usually made by obtaining permits granted by the CRE or the SENER, along with other required authorisations from other regulatory agencies such as the COFECE or the ASEA, depending on the specific activity.

The following is a brief overview of the allowed private investments in midstream and downstream operations.

• Crude treatment – this refers to industrial processes for oil conditioning performed outside of an exploration and production area and prior to refining. Hydrocarbons stabilisation within such area is excluded from this.
• Gas processing – this involves physical and chemical processes applied to natural gas and associated condensates to obtain refined products and petrochemicals.
• Refining –this involves physical and chemical processes applied to oil to produce refined products and petrochemicals.
• Storage – this involves depositing and safeguarding hydrocarbons, refined products and petrochemicals in storage facilities.
• Transportation – this includes receiving and delivering hydrocarbons, refined products and petrochemicals from one place to another by pipelines, trucks, vessels or other means. It does not involve the transfer of title to or marketing of transported products, and it excludes the gathering of hydrocarbons within the E&P area.
• Distribution – this includes purchasing, depositing and delivering NG or refined products from a specific location to one or several assigned destinations for its retail sale or final consumption.
• Marketing – this involves the purchase and sale of hydrocarbons, refined products or petrochemicals; management of transportation, storage, or distribution services; and/or intermediation services. Marketers do not own infrastructure.
• Retail sale – this involves sales performed directly to the end-user of NG or refined products in facilities with a specific or multi-modal purpose.

Investors, both local and foreign, including IOCs, are participating in the Mexican midstream and downstream markets. Foreign investors typically set up special purpose vehicles in Mexico to invest, as local regulations require energy permits to be obtained and maintained by Mexican entities.

In Mexico, as a result of the 2013 energy reform, there is no longer a downstream state-run monopoly, with the exception of the into-plane activity in aviation fuel distribution. Despite this, Pemex, which held a near-monopoly for almost 80 years, still retains 50% or more market share in many downstream markets.

The Hydrocarbons Law, implemented as part of the energy reform, provided certain levelling measures in midstream and downstream sectors to promote competition. One of these measures was the unbundling of first-hand sales from Pemex’s trademark, which allows private participants to retail Pemex’s products under their own brands.

Regarding access rights, the regulatory bodies have enacted various rules to ensure open and non-discriminatory access to midstream infrastructure (like pipelines and storage), most of which is still owned by Pemex. The CRE sets and oversees the tariffs for using these infrastructures.

The methodologies for setting these tariffs take into consideration various factors, including recovery of investment, operation and maintenance costs, and a reasonable rate of return. Tariffs are typically revised and updated on a regular basis.

As for challenging rates and other terms of service, market participants have the right to file a complaint with the CRE if they believe that they are being charged excessive or discriminatory rates. The CRE then has the authority to investigate these complaints and take corrective action if necessary.

Private participants also have the right to challenge CRE’s decisions before the federal courts. If they believe that a decision is unlawful or unfair, they can file an amparo lawsuit, which is a form of constitutional protection provided by the Mexican legal system.

In terms of downstream operations where private investment is permitted, these are open to both domestic and international investors. Regulatory approvals are required from the CRE or the SENER, along with other authorisations from other relevant agencies depending on the specific activity.

As explained above, midstream/downstream activities are not subject to a concession regime but rather to a permit framework. As a result, any interested party (either public or private, domestic or international) meeting the required criteria under applicable law may apply for a midstream and/or downstream permit.

Any interested party shall submit a permit application before the CRE or SENER (depending on the type of permit). As a general rule, permit applications involving infrastructure (such as pipeline transportation and storage) require the applicant to comply with more complex requirements including, among others, financial and operational capabilities of the applicant, description of the proposed infrastructure, corporate structure and open season requirements (for infrastructure subject to open-access obligations). Permits that do not require infrastructure (ie, marketing permits) have laxer conditions limited to financial and corporate requirements of the applicant.

As a result of the COVID-19 pandemic, CRE and SENER suspended the processing of new permits (or amendments to the existing ones) for more than two years. Although both agencies have resumed obligations, CRE (who is in charge of the vast majority of midstream and downstream permits) is only partially open for processing new applications, based on a quota (tickets) system allowing only a limited amount of applications to be filed each month. However, such ticket system has been judicially challenged successfully by several applicants (resulting in certain cases in an “expedite” process).

In Mexico, commercial arrangements for midstream and downstream operations typically take the form of privately negotiated service agreements. These contracts are established between the service provider, who holds the permit and the user or end user. These agreements are subject to the jurisdiction of the COFECE, which ensures market conditions are fair and competitive for all participants.

Despite the freedom to negotiate terms, there are exceptions where certain activities are subject to specific regulations. Midstream operations that involve open-access obligations, including the storage and pipeline transportation of natural gas and refined products, are subject to tariff regulations and must have their General Terms and Conditions (GTCs) pre-approved by the CRE.

The CRE, which is responsible for authorising GTCs and applicable tariffs, does not prescribe a specific tariff or pricing structure for each service. Instead, the CRE ensures that the proposed tariffs have been calculated according to regulatory guidelines and that the pricing reflects a reasonable profit margin for the permit holder, given the specifics of each project. Any discounts offered on these tariffs must be non-discriminatory.

The GTCs, which should include the form of the service agreement as an exhibit, are drafted by the permit holder following mandatory guidelines provided by the CRE. These guidelines stipulate the minimum requirements that all GTCs must meet, and the final GTCs are ultimately subject to approval by the CRE.

The regulations accommodate different service modalities for pipeline transportation services, including both firm and interruptible services. Firm services are guaranteed capacity services, while interruptible services are provided as and when capacity is available. The pricing of these services, as well as the negotiation of take-or-pay or volume commitment clauses, will be largely driven by the specifics of each individual agreement and the relevant market dynamics.

Midstream and downstream operations in Mexico are taxed similarly to other non-energy-related commercial activities. The tax structure for these operations includes the following

• Value-added tax – this is typically charged at a 16% rate. However, activities performed in the northern border region of Mexico (the USA-Mexico border area) may be subject to a lower rate. The import and export of goods can also attract lower VAT rates, sometimes as low as 0%.
• Income tax – this is levied at a ramp-up rate of up to 30%. Various deductions are allowed under the law.
• Excise Tax – this is only applicable to certain goods like gasoline and diesel, with rates varying depending on the type of good.
• Governmental fees – these are charged for the issuance and maintenance of certain permits required for midstream and downstream operations.

It is important to note that Mexico’s tax system does not offer specific tax exemptions or incentives for midstream and downstream operations. These operations are treated in the same way as other commercial activities. However, general tax benefits or incentives available under Mexican tax laws, such as deductions for investments in certain types of equipment or technology, may apply depending on the specifics of each case.

Under Mexican law, there are certain provisions that could potentially give special rights to Pemex or other State Productive Entities in relation to midstream and downstream activities. These include the following.

• Mandates by SENER – SENER can instruct Pemex or any other SPE to perform certain midstream and downstream activities. Such activities would be financed with public funds and require approval from the CRE and the Ministry of Finance.
• Temporary Operation of Private Facilities – SPEs may temporarily operate any private facilities that have been intervened by the Mexican government due to the takeover process described under the Hydrocarbons Law.
• Expedited Permit Issuance – in practice, there have been instances where retail permits for Pemex-branded gas stations have been issued faster than permits for non-Pemex retail stations (including white flag stations). However, this preferential treatment is not explicitly provided for under Mexican law.

These rights or practices can potentially give Pemex or other SPEs a competitive advantage in midstream and downstream operations. However, it’s important to note that all market participants, whether private or public, are subject to the same legal and regulatory obligations.

Unlike the upstream sector where local content percentage serves as a key criterion in awarding an E&P Contract, there are no specific local content requirements in midstream and downstream activities for private investors under Mexican law. Thus, private investors are not legally obligated to prioritise local goods, services, employment, or training programmes in their midstream or downstream operations.

The current framework for midstream and downstream licences in Mexico is largely shaped by principles of open access and field-levelling rules, which aim to foster competitive energy markets. This has been advantageous for private entities, leading to considerable growth in Mexico’s energy infrastructure.

However, there are challenges that need to be addressed. These include the absence of maritime storage terminals and security concerns surrounding pipeline use across Mexico, which pose a significant hurdle to the full development of energy markets, particularly in the country’s southern region.

Moreover, the recent shift in energy policy, primarily aimed at moving away from the open market principles instituted in 2013, has created an environment of uncertainty. This has resulted in delayed private investment in the Mexican energy sector.

Nonetheless, the nearshoring demands appear to be stimulating both private and public investment in power and O&G infrastructure. This indicates a potentially positive trajectory for the sector despite the current uncertainties.

The structure of the midstream and downstream licences includes service obligations and classes of service, with no specific domestic supply requirements or export rights detailed in law. The liability and risk regime is based on contractual arrangements and general laws, and there are no specific withdrawal, termination or abandonment rights and obligations beyond what would be provided in the applicable contracts or permits.

In Mexico, eminent domain rights, or derecho de expropiación, are vested in the government. This means that the Mexican government has the authority to expropriate any assets, including real estate, considered of public interest. This can be done provided that specific requirements detailed in the Eminent Domain Law are fulfilled. The compensation for the expropriated assets is typically determined based on their commercial valuation rather than the tax valuation assigned by the state.

These general eminent domain rights also extend to midstream and downstream activities in the O&G sector. The Hydrocarbons Law provides for provisions that permit temporary occupation or intervention by the Mexican State (usually through an SPE) of private midstream or downstream facilities in order to “guarantee the Nation’s interest”. The conditions required for such temporary occupation or intervention are considerably less stringent than those outlined in the Eminent Domain Law.

The transportation of hydrocarbons via pipelines, particularly natural gas and refined products, is primarily regulated at the federal level by the CRE, with no local state or municipal counterparts.

From a regulatory standpoint, the transportation/distribution of natural gas and refined products via pipelines is among the most heavily regulated activities in the midstream sector. Consequently, these operations are subject to specific regulations regarding pricing and contractual arrangements, all of which are approved by the CRE. These regulations also enforce open access obligations, including the execution of open season procedures for allocating available capacity.

Additional conditions may apply, considering the restrictions on vertical integration and cross-ownership to be issued by the COFECE and the CRE on a case-by-case basis.

Securing relevant environmental authorisations from the ASEA and the social impact assessment from the SENER are essential steps in the development of any pipeline transportation/distribution project. This is due to the disruptive impact such infrastructure can have on existing environments and communities.

In Mexico, as a general rule, pipeline transportation/distribution and storage services must adhere to open-access and non-discriminatory restrictions. This implies that these services should be made available to all market players without unjust discrimination.

However, refined products storage services are not fully subjected to these open-access conditions (such as tariff regulation and capacity allocation via open season procedures) unless the CRE determines a given storage project as crucial for the respective market development. Natural gas storage, in contrast, is fully regulated by the open-access regime.

For pipeline transportation services for either refined products or natural gas, full open-access regulations apply unless a particular pipeline is authorised for self-use. Self-use pipelines are usually owned by end-users for industrial purposes and are exceptions to the rule.

Open-access regulations encompass several key points, including:

• non-discriminatory access to services – services can only be refused by the permit holder if the system doesn’t have available capacity;
• interconnections and system expansions cannot be denied unless they are not feasible or economically viable;
• sizing of transportation capacity and allocation of available capacity must be carried out via an open-access procedure;
• approved tariffs must offer discounts to all users under similar circumstances;
• any deviations from the approved service agreement form must be reported to the CRE; and
• GTCs must include, at a minimum, the terms and conditions stipulated in the applicable guidelines.

It’s also worth noting that there are no provisions that prohibit the same entity from providing services across multiple segments of the market. However, this is subject to case-by-case restrictions on vertical integration and cross-ownership, as determined by the COFECE and the CRE.

In Mexico, those who trade in refined products and natural gas must obtain a marketing permit from the CRE, irrespective of the origin of the traded products or their customers (including users, end users, or other permit holders). Under the law, all permit holders are also prohibited from owning or providing any service in connection with illicit products. Consequently, permit holders must be able to demonstrate the legal origins of the products they handle or trade.

Imports and exports of goods in Mexico are subject to general foreign trade rules, which may include specific duties or quotas for particular products. Some energy products, such as gasoline, diesel, crude oil and propane/butane mixtures, require a special permit from the SENER. This list of products is updated periodically.

Certain products may require an export permit but not an import permit, such as natural gas. Conversely, others may require an import permit but not an export permit, such as propane mixtures.

Import permits may be granted for a period of either one or five years, with 20-year permits no longer being available. It is notable that during the administration of President AMLO, the issuance of new permits significantly declined, and SENER also revoked some existing 20-year permits.

In Mexico, the transfer of midstream and downstream operations and assets between private owners requires strict adherence to legal requirements. The assignment of rights of any permit title from the current permit holder to any third party is subject to prior authorisation from the CRE or the SENER, depending on the specific case.

Each permit type has specific requirements for its transfer, but generally, permit transfers may only be authorised when the prospective assignee can fully demonstrate to the relevant governmental authority that they possess at least the same capabilities as the assignor.

Further, restrictions on the change of control of the permit holder may also apply, depending again on the type of the underlying permit.

In cases where the transaction size meets certain monetary thresholds, pre-merger approval from the COFECE may be required. Additionally, cross-ownership authorisation from CRE and COFECE may also be needed in certain scenarios, particularly when the proposed transfer involves infrastructure subject to open access obligations.

These requirements often mean that transfer of midstream and downstream operations involves careful planning and co-ordination, including ensuring compliance with regulatory obligations, handling contractual issues, and managing potential risks and liabilities. It’s always advised that entities involve legal and industry experts in the process to ensure a smooth and compliant transfer.

In Mexico, the regulations on foreign investment in the energy sector have been relaxed since the energy reforms of 2013. The only major restriction pertains to aviation fuel supply, where direct foreign investment is capped at 49%.

All other midstream and downstream activities are open for up to 100% foreign ownership, provided that the Special Purpose Vehicle (SPV) which acts as the permit holder is incorporated as a Mexican entity.

Mexico has a comprehensive legal framework that includes protection against expropriation, and any expropriation must be for public utility reasons and subject to the payment of appropriate compensation. The legal system also provides stability provisions, and the ability to implicate international law. Mexico is a party to several international treaties that provide protections for foreign investments, including the ability to resort to international arbitration.

However, it is essential to note that the current administration (as of the last update in 2021) has exhibited some tendencies to roll back parts of the 2013 energy reforms, which could impact foreign investment trends in the future.

Mexico itself does not impose sanctions on investing in energy assets in any particular foreign jurisdiction or conducting business with specific foreign counterparties or governments.

Investing in energy assets in any particular foreign jurisdiction or conducting business with specific foreign counterparties or governments does not incur any sanctions.

Mexico, as a member of the international community, generally complies with United Nations-imposed sanctions.

In Mexico, environmental laws and regulations play a crucial role in shaping the O&G industry, impacting everything from exploration and extraction to refining and distribution. These laws and regulations are not only designed to protect the environment but also to ensure that the country’s natural resources are used in a sustainable manner.

The principal environmental regulator for upstream, midstream and downstream operations is the ASEA. This governmental agency falls under the Environmental and Natural Resources Ministry (SEMARNAT) and holds the authority to enforce environmental regulations across the energy sector.

• The Law of the ASEA outlines the internal administration of ASEA and its authorities. It provides a legal framework for ASEA’s supervision over health, safety and environmental protection within the energy sector.
• The Hydrocarbons Law addresses the social impact assessment and the requirement of free, prior and informed consent. The SENER has authority over both requirements.
• The Environmental Protection and Ecological Balance General Law and Regulations is responsible for important environmental permits, such as the environmental impact assessment, ensuring the preservation of the ecological balance.
• The Environmental Responsibility Federal Law and Regulations outline the consequences and penalties for breaches of environmental laws and regulations, aiming to ensure compliance.
• The Hazardous Management and Prevention General Law focuses on the proper handling and management of waste materials to mitigate potential hazards. ASEA also oversees the implementation of this law.

Additional regulations may include the General Law on Sustainable Forestry Development, the National Waters Law and the National Goods Law. Each of these contributes to the holistic approach to environmental management in the country’s O&G sector.

In Mexico, embarking on a major hydrocarbon project requires satisfying several crucial environmental obligations. These obligations aim to mitigate potential environmental damage, protect local communities, and ensure compliance with environmental and safety standards.

Key authorisations for O&G projects include the following.

• Preparation of an Environmental Impact Assessment (EIA) and a risk analysis for the hydrocarbon sector. The EIA provides a comprehensive evaluation of the potential environmental impacts of a proposed project, and the risk analysis evaluates possible risks associated with the project.
• Obtaining authorisation from environmental authorities for any changes in land use, including changes in the use of forestry land if applicable. This is to ensure that project operations do not negatively impact the environment.
• Authorisation of the Management System for Industrial, Operational, and Environmental Safety. This integrated management system is designed to improve industrial and operational safety and environmental protection.
• Preparation of an environmental baseline to determine pre-existing environmental damage and liabilities, ensuring that the project operator is not held accountable for any pre-existing environmental issues.

Before construction can commence, O&G projects must obtain EIA approval from the ASEA. The EIA must include environmental surveys, a description of the project area, and an assessment of potential environmental impacts along with mitigation plans. ASEA typically takes 60 business days to issue authorisation, which can be extended to 120 business days in some cases. ASEA can approve or deny the EIA and may impose conditions such as specific mitigation measures.

In line with the Hydrocarbons Law, a social impact assessment must also be submitted to the SENER for its evaluation. Upstream and midstream/downstream activities cannot commence until a resolution is issued. If SENER determines that the project requires prior, free, and informed consent, it initiates a consultation process with indigenous peoples and local communities in the project area.

SENER bears full responsibility for this consultation process, which can result in project delays. Unlike other jurisdictions where private companies can directly develop this process, in Mexico, this process is solely handled by SENER. This process typically takes 90 business days, but since 2019, it has often taken several years, causing significant project delays.

Finally, Mexico’s legal system allows individuals, organisations, or communities affected by environmental harms to file environmental class action suits. These suits can either seek to hold entities accountable for environmental harm or collectively seek compensation for damages. Federal Courts adjudicate these cases.

Offshore development projects follow similar environmental obligations to onshore projects, but there are additional requirements owing to the unique environmental and safety challenges these projects pose. A crucial element is that these projects need a comprehensive spill prevention and response plan integrated into their Management System for Industrial, Operational, and Environmental Safety.

Moreover, the Ministry of Infrastructure Transportation and Communications may mandate additional environmental, health and safety requirements for offshore projects, particularly when these involve dredging at the site or the use of the seabed. It is therefore essential for any offshore development project to have an exhaustive understanding of the EHS requirements specific to offshore operations to avoid non-compliance and potential liability.

Decommissioning in the O&G sector refers to the process of safely retiring and removing oil and gas infrastructure once production activities have ceased. In Mexico, this includes activities by E&P contractors and midstream permit-holders aimed at removing and dismantling equipment, installations and materials. It covers the permanent plugging and technical closure of wells, removal, and dismantling of all plants, platforms, facilities, machinery and equipment used during the activities. Additionally, it involves environmental damage restoration in the area affected by the contractor, in terms of industry best practices, and the Management System for Industrial, Operational and Environmental Safety.

A distinct element of upstream projects is the requirement for E&P contractors to establish a decommissioning trust before commencing development activities. The trust’s funds will increase through quarterly contributions by the E&P Contractors, calculated based on an annually updated estimated amount required for decommissioning, the estimated production, and the remaining estimated reserves.

E&P contractors must also conduct an environmental baseline study, as set out in the E&P Contracts, to contrast it with the baseline study completed when the E&P Contract was executed. Contractors are held responsible for any environmental damages within the Contract Area and are obligated to restore and compensate for such damages.

Mexico has been proactive in addressing climate change and was among the first countries to ratify the Paris Agreement. Under this agreement, Mexico pledged to reduce its greenhouse gas emissions by 22% by 2030, with the potential to increase this reduction to 36% with international support.

The country’s primary legislative response to climate change is encapsulated in the General Law on Climate Change. This comprehensive legislation mandates the reporting of greenhouse gas emissions and requires certain entities, including large-scale industrial facilities, energy producers, and transportation operators, to measure, report, and verify their greenhouse gas emissions. However, only industrial and energy sector facilities exceeding the 100,000 total carbon dioxide thresholds must report their emissions.

Mexico has also introduced the Mexican Emission Trading System, based on the “cap and trade” principle, as a strategic measure to reduce emissions. This system, still in its pilot phase, makes Mexico the first Latin American country to regulate such a system.

Notably, however, there has been a shift in Mexico’s climate change policy under President AMLO’s administration. The government has prioritised the use of fossil fuels and dismantled key climate change tools and institutions, including the Climate Change Fund. As a result, the Climate Action Tracker has assessed Mexico’s climate change commitments as critically insufficient.

Although local governments in Mexico don’t have jurisdiction over O&G development, they still hold considerable influence over such projects. Municipalities, in particular, have the authority to grant or deny critical authorisations such as land use permits, operation licences and other civil protection authorisations. Furthermore, local zoning ordinances can significantly limit the development of energy projects. This means that while the direct control of O&G development may not lie in their hands, local governments can exercise indirect control by regulating related areas.

While fracking is technically permitted under applicable law, and ASEA has issued secondary regulations addressing environmental risks associated with fracking activities, the practice has yet to be authorised by the CNH for any project. Moreover, President AMLO has indicated that he will not authorise any fracking during his administration. Therefore, it’s unlikely that any unconventional upstream activities, such as shale, heavy oil and coal-bed methane extraction, will take place in the near future.

LNG projects in Mexico are subject to specific regulations and permits. They require a liquefaction permit from the CRE and an export permit from the SENER. The latter is granted only if the export of LNG doesn’t negatively affect domestic natural gas balance and supply.

Previously, LNG export permits could be granted for periods of either one or 20 years. However, a recent regulatory change under AMLO’s administration has limited the maximum term for export permits to five years. Any 20-year permits granted before 2020, though, remain valid until their expiration.

Despite some delays, SENER has granted LNG export permits to several privately owned companies. The US Department of Energy has also granted export permits, with Mexico continuing to be one of the major destinations for these exports.

Given the high global demand for natural gas, there is a rise in LNG infrastructure projects in Mexico. These include Energía Costa Azul in Ensenada, Baja California; Vista Pacífico in Topolobampo, Sinaloa; Mexico Pacific Limited in Puerto Libertad, Sonora; New Fortress in Altamira, Tamaulipas; and an LNG Alliance in Guaymas, Sonora.

It is worth noting that to meet the gas supply demand from these LNG facilities, an expansion of the transportation capacity of existing cross-border pipelines, or the development of new pipelines, will be necessary. The shared cross-border facilities with the United States can import approximately 12 billion cubic feet of gas per day through 24 import points.

Energy transition considerations have had a significant impact on the development and utilisation of O&G upstream and midstream assets in Mexico. The 2013 energy reform, which drove the reform process, aimed to address the social and environmental impacts associated with the transition.

Mexico has the potential to become a leading producer of green hydrogen, according to the German Agency for International Cooperation (GIZ). With existing renewable energy resources, such as solar and wind, the country has the capacity to install up to 22 terawatts of electrolysis, producing approximately 1.4 billion tons of green hydrogen. States with significant potential for green hydrogen production include Chihuahua, Coahuila, Sonora, Durango, Nuevo León, Zacatecas, Tamaulipas, Campeche, San Luis Potosí, and Veracruz.

The Electric Industry Law of 2014 introduced a wholesale electricity market and implemented Clean Energy Certificates (CELS) to incentivise the development of clean energy power plants. Load Centres are required to meet specific clean energy requirements by sourcing electricity from clean sources or acquiring CELs. These certificates, issued by the CRE, represent energy generated from clean sources and aim to reduce greenhouse gas emissions while providing additional revenue for clean power plants.

However, recent regulatory changes implemented by the AMLO administration have deviated from the objectives set by the 2013 energy reform, particularly affecting the generation of CELs. Amendments to the electricity law approved by the Mexican Congress have been subject to constitutional challenges filed by various industry players, non-governmental organisations (NGOs), the Mexican Senate, the COFECE, and state governments. While the Mexican Supreme Court has ruled some changes as unconstitutional, the decision did not reach the threshold required to declare unconstitutionality with general effects. Therefore, affected private individuals must individually submit judicial claims.

Additionally, it’s worth noting that in May 2023, the CRE issued a resolution that artificially increased the amount of clean energy in the wholesale market. This involved classifying combined cycle plants as fossil-free power plants, granting them eligibility to acquire CELs. This resolution has received public reactions from different associations and NGOs, but no public legal remedies have been announced yet.

While there are currently no public international bids for E&P Contracts in Mexico, several private O&G companies are already producing oil and gas in the country and others are expected to commence production in the coming years.

Joint projects with state-owned companies Pemex or CFE present opportunities for other companies interested in conducting E&P activities in Mexico. For instance, New Fortress Energy executed a farm-out agreement with Pemex in 2022 to jointly develop Lakach, a deepwater natural gas field in the Mexican portion of the Gulf of Mexico.

Private O&G projects, including storage, transportation and liquefaction, are permitted under the legal framework. However, such projects are more likely to succeed when undertaken in alliance with a SPE. As an example, TC Energy and CFE announced their decision in August 2022 to invest in the construction of a 444-mile underwater natural gas pipeline from Tuxpan Port to the Olmeca Refinery in Dos Bocas, Tabasco. This project, with an estimated investment of USD4.5 billion, is expected to commence operations in 2025.

Additionally, Sempra Infrastructura (a subsidiary of Sempra Energy), Carso Energy (a Mexican O&G company), and CFE have entered into an agreement to develop a pipeline connecting existing pipelines in Baja California with Sonora.

It is worth noting that in June 2024, Mexico will hold general elections, including the election of a new President for a six-year term, 500 members of the House of Representatives, and 128 members of the Senate. The outcome of these elections may have implications for the hydrocarbon industry and future energy policies in the country.

Since the AMLO administration took office, there have been several material changes in O&G law and regulation in Mexico. However, most of these changes have faced legal challenges and have not been fully implemented. The key material changes are as follows.

• In June 2022, SENER issued an official letter requiring users of Mexico’s natural gas transportation system to prove that they received the gas supply from specific SPEs. This decision has been challenged through constitutional claims filed by several companies, the COFECE and state governments. A definitive injunction has been granted, suspending the effects of the official letter, and the claims are still pending resolution.
• Consultations were requested by the United States and Canada under the United States-Mexico-Canada Agreement (USMCA) concerning Mexico’s energy policies. Negotiations between the three countries are ongoing.
• In February 2023, the SENER issued a decree uplifting the terms and deadlines of procedures carried out by the SENER from 1 March 2023. These deadlines had been suspended since 24 March 2020, due to the COVID-19 pandemic. A similar decree was issued by the President of the CRE, establishing new deadlines for resolving procedures submitted between 18 January 2021, and 23 January 2023. Constitutional claims have been filed against this decree, and some companies have been granted injunctions against its implementation. The claims are currently being processed.
• As mentioned in 6.3 Energy Transition Considerations, in May 2023, the CRE issued a Resolution that artificially increased the amount of clean energy in the wholesale market by classifying combined cycle plants as fossil-free power plants. This decision has faced opposition from various associations and NGOs, but no public legal remedies have been announced yet.
• The transitory provisions of the Hydrocarbons Law originally granted the CRE the authority to impose asymmetric regulatory principles on certain hydrocarbon sales and commercialisation activities. However, on 19 May 2021, the Federal Congress removed this provision, leading to the elimination of all general provisions related to asymmetric regulation by the CRE. Several private companies filed claims against these actions, and on 15 June 2023, the Supreme Court ruled them unconstitutional, reinstating the original regulation.