Mexico has a state-ownership principle with respect to hydrocarbons. Under the Mexican Constitution, all domestic hydrocarbons belong to the nation, which then entrusts different operators with their exploitation. No rights or claims to the hydrocarbons are contemplated for states, municipalities, other political subdivisions or any other constituencies, such as indigenous groups. Given this principle, all matters related to the oil and gas industry (including at the midstream and downstream level) are handled at the federal level.
In 2014 Mexico underwent a sweeping reform of its energy industry that resulted in an overhaul of the sector, and a complete opening of the industry to private investment and competition. Prior to 2014, Mexico had a vertically-integrated monopoly in the oil and gas business. The national oil company, Petróleos Mexicanos (known as Pemex) was the single exploration and production (E&P) operator. At this time there was a general lack of understanding as to the resources’ ownership structure: people tended to believe that the oil and gas was owned by Pemex, whereas in fact Pemex was merely the operator.
After the reforms, the constitutional principle remained unchanged in the sense that the nation remained the owner of hydrocarbons. The only change was that the exploitation of the resources was opened up to a multiplicity of operators. Geology and geophysics (G&G) data is likewise owned by the nation (subject to commercial rights of those who acquire/develop it), being able to license out such data to operators and other private parties.
The Hydrocarbons Law (enacted in 2014 to restructure the market with the reform) organises the regulation of the oil and gas sector in a bifurcated manner: upstream is regulated by the National Hydrocarbons Commission (Comisión Nacional de Hidrocarburos, CNH) – see www.gob.mx/cnh – while the Energy Regulatory Commission (Comisión Reguladora de Energía, CRE) – see www.gob.mx/cre – is entrusted with the regulation of midstream and downstream, including transportation, distribution, storage and marketing of both hydrocarbons and refined products. The Ministry of Energy (Secretaría de Energía, SENER) – see www.gob.mx/sener – which is mostly the policy-maker and the co-ordinator with respect to energy planning, maintained regulatory powers on the side of refining (including permitting for new refineries and for the existing Pemex refineries) and gas processing, and on the imports and exports side (both for hydrocarbons and products), primarily given its role in safeguarding national energy security. SENER likewise regulates the so-called minimum inventory for refined products.
In addition to such a structure, the 2014 reform opted for an additional bifurcation with respect to health, safety and the environment (HSE), which is handled by a separate environmental agency created specifically for the oil and gas industry, as further described below.
Oil and gas activities are exclusively regulated by the federal government. No state or local government has regulatory powers over the industry.
While the 2014 reform opened the sector to private operators, it maintained Pemex (see www.pemex.com) as the largest and preponderant operator, on the upstream side, and as an additional player (with market preponderance as well), for the rest of activities. Given that the reform did not call for a divestiture of assets by Pemex, the NOC maintained the assets that it previously had as a legal monopoly, including all existing refineries, a network of logistics terminals and pipelines for products, and a strong presence in the natural gas sales market, among others. We note that the reform did call for the spin-off of the natural gas transportation network, but to another government instrument, the National Centre for Control of Natural Gas (CENAGAS).
A new statute, the Pemex Law (Ley de Petróleos Mexicanos), was enacted to provide for the new Pemex structure, and to set its clear mandate: to create economic value in the industry. For that, Pemex’s main purpose was to be a profitable exploration and production company, while midstream and other activities were set as optionalities. With respect to its E&P activity, with the 2014 energy reform Pemex was granted through the so-called 'Round Zero' all the fields it was currently producing, and a portion (approximately two-thirds) of those in which it was undergoing exploratory works prior to the reform. The rest of the reservoirs and fields in the country were released for administration by the CNH on behalf of the Mexican State.
The 2014 reform also provides for regulated farm-out tender processes of Pemex oil and gas interests. Any oil and gas rights held by Pemex as part of Round Zero may be farmed-out to private parties; the selection of the farmee(s) (who takes a participation interest determined on a case-by-case basis) is undertaken through a competitive bid process organised by the CNH.
The legal framework governing Mexico’s oil and gas sector is comprised mainly by the following statutes and regulations.
In addition to the foregoing, note that the statutory framework provides CRE, CNH and ASEA with broad rule-making powers for interpreting the laws and implementing further regulations, which they do in the form of General Provisions governing a number of issues, from rules for bids on the upstream side to rules for open access on midstream assets.
The aforementioned statutes and regulations have been in effect for almost five years. No major overhaul to any of these instruments is expected. For the first time, however, ASEA has introduced amendments to its regulation following feedback from the industry.
A private operator may conduct the activities of exploration and extraction of hydrocarbons – ie, explore for, develop and produce, through an E&P contract (which constitutes the 'upstream licence') granted by the CNH on behalf of the Mexican State. The CNH grants the contract to the private operator in the context of a competitive, international public bid, on the basis of maximisation of value for the state. The legal framework contemplates that the E&P contracts can be of several types: profit sharing, production sharing, licences, risk-service, a combination of these, or other modalities. The contract is given for a contractual area (an area delimited by geographic boundaries, geological formations or a combination of both), for a specific term and allows the operator to exclusively exploit the hydrocarbons in the area upon payment of consideration to the state. No property rights are granted over the hydrocarbons in situ; thus, private operators are not allowed to mortgage, dispose of or otherwise encumber those resources while they remain in the subsoil.
Whether the relevant block or area is exploited through a licence, a production sharing contract (PSC) or other, as well as the associated terms, is determined by the CNH with SENER (with the participation of the Ministry of Finance regarding base values for the setting of the government take).
Although the legal framework allows the use of risk service contracts and profit-sharing contracts, the Mexican government has not used any of these contracts in the oil and gas rounds called thus far.
Based on pre-defined areas of interest which are identified in a five-year national strategy by SENER, with the technical input of CNH (and also based on statements of interest in specific areas by private parties), the CNH launches a round or series of bids to award upstream contracts/licences for each specific area. All awards of contracts are subject to international bids conducted under strictly public and open processes, on the basis of the party offering the best economic conditions to the state. In order to participate in a bid for a given contractual area, the CNH publishes the technical and financial criteria that must be satisfied by the bidder. These include, with respect to technical capabilities, the experience in operation of fields of a certain nature, whether at the level of the company or of its key personnel. From the financial standpoint the bid rules also require a certain minimum net worth for bidders to participate. These requirements can typically be satisfied by a single bidder or on an aggregate basis by the members of a consortium, subject to special rules and restrictions.
Bidders are generally required to post a bid guaranty, in the form of a bond or letter of credit, and a corporate guaranty from the parent company to be in place during the life of the contract.
Companies holding an E&P contract are required to be incorporated in Mexico, and thus with local presence from the tax and legal perspective, with a permanent domicile in Mexico (although, as further described below, no restrictions on foreign ownership exist).
The decision on when to undertake bid rounds is part of the policy-making authority and lies on the discretion of SENER.
Other than standard permits and authorisations for E&P projects, such as HSE (including a so-called management system) and surface agreements with landowners, if an operator is awarded a licence/contract with ongoing oil and gas production (ie, previously operated by Pemex or another private operator), in order to market the production domestically, whether to a trader or end user, the operator requires a trading permit issued by the midstream regulator, CRE.
Pursuant to the Hydrocarbons Revenues Law, under a license contract scheme, the State shall receive:
Under profit and production sharing contracts, the State shall receive:
Furthermore, each E&P Contract includes a so-called 'adjustment mechanism' which is intended to largely capture the windfall profits for the Mexican State. This mechanism works as a formula established by the Ministry of Finance that modifies one of the parameters to calculate the considerations under an E&P Contract. In the case of royalties, the Hydrocarbons Revenue Law establishes the formulae to calculate them, taking into account the variations in the US Consumer Price Index.
The above-mentioned monies shall be paid to the Mexican Petroleum Fund (Fondo Mexicano del Petróleo para la Estabilización y el Desarrollo) for their management and distribution under applicable statute.
In the case of onshore projects, operators are also required to pay a certain percentage of the production to the landowners of the areas where the production takes place. These fees vary from 2% to 3%, depending on the type of hydrocarbon and revenues generated by the project.
Private operators are subject to the applicable corporate income tax incurred under the Income Tax Law (Ley del Impuesto Sobre la Renta), currently at 30%. In addition, there is an exploration and production tax payable by all operators. This tax is calculated based on acreage held by the operator and it varies on whether the acreage is held for exploratory or production activities.
Furthermore, for purposes of income tax deductions pursuant to the Hydrocarbons Revenue Law, contractors shall be able to apply the following percentages on amortisation related to upstream activities:
Pemex was given a right, through the so-called Round Zero, to keep all its production fields and a relevant portion of its then-ongoing exploration projects. Pemex maintains the operation of these fields through 'entitlements' or state licences, which are subject to a more stringent fiscal regime for Pemex than that imposed on others. If Pemex so decides, it has the right to 'migrate' such areas into the new regime and convert them into E&P contracts (production sharing or licences). For that purpose, Pemex may secure a joint venture partner for the relevant block or do it at its sole risk. As a particularity, the process to elect the partner for Pemex is not handled by Pemex itself, but for transparency reasons, this is left for the CNH, which manages a competitive bid to determine the partner on the basis of the maximum value of the royalty and of the investment committed by the partner in the 'farm-out' venture. Given the amounts that Pemex has invested in such areas, the investor is required to either 'carry' the investment required for Pemex or pay a 'farm-in price' in consideration for prior investments made by Pemex and an undivided interest in certain infrastructure and assets related to the project.
Other than the above, we note that the legal framework does not demand a certain minority participation by Pemex in other blocks that the CNH may offer, or Pemex becoming the operator of the block, although the law contemplates the possibility of demanding such mandatory participation in cases of potential transboundary fields, if so determined by the regulator.
E&P activities are required to reach a 35% national content by 2025 (deep water and ultra-deep water E&P activities are excluded from this provision). However, the mechanism to measure the national content depends on the type of the exploration or production areas, as well as the fields. Such mechanism to reach the above-mentioned goal is established by the Ministry of Economy, whereby the following factors shall be considered:
The Ministry of Economy has issued regulatory instruments that include a methodology to measure national content in E&P contracts, entitlements (exclusive to Pemex) and midstream permits, as well as the rules to provide national content information to the government.
Furthermore, Mexican labour laws require that private entities employ at least 90% Mexican nationals. However, this provision does not apply to directors or senior management. Furthermore, the law permits corporations to hire 10% of specialised employees on a temporary basis, mainly aiming for employees to train and transfer their knowledge to the Mexican employees
In the event of a discovery in the initial exploration period the licencees and/or contractors shall submit an appraisal plan to the CNH for approval. After the end of the appraisal period, the contractor shall inform the CNH whether it considers the discovery to be a commercial discovery; in such event the contractor shall submit a development plan to the CNH for approval.
As a general rule, since the licencee or contractor carries the risk of commercial profitability of the areas subject to development and production, operators can define the means for development and production. Nevertheless, CNH has the authority to render observations to such development plans to ensure consistency with the corresponding contract and the Hydrocarbons Law. The licencees or contractors shall make the corresponding adjustments and operating solutions to the development plans in order to comply with the aforementioned observations.
In the event of disagreement or deadlock over the development plans, in most contracts the contractor may pursue the dispute-settlement mechanism established under the contract, mediation procedures to be followed by the parties or, ultimately, arbitration. The licencees/contractors have the right to relinquish part of the block awarded, or even to terminate the relevant contract early, subject to certain rules (eg, complying with a minimum work programme, abandonment rules, etc).
If the CNH does not respond to an application for approval of an exploration or development plan within the 185 calendar days following the reception of the application, the plan submitted for approval is deemed approved.
Hydrocarbons in the subsoil shall be the property of the nation. However, upon extraction and payment of the corresponding royalties, in the case of a licence, the licencee is entitled to take title to the hydrocarbons and dispose of them. In the case of production-sharing contracts, the contractor shall deliver the hydrocarbons produced and receive from the Mexican Petroleum Fund the share of production belonging to the contractor (ie, after payment of the government share, and all royalties and fees). In addition, under PSCs, the contractor may be entitled to reimbursement of 'recoverable expenses' provided that the expenditures have a reasonable basis according to industry standards and satisfy a number of specific requirements established under the E&P contract and the applicable laws and regulations. Note that the reimbursement is subject to a certain maximum of the revenues generated and recovery is contingent upon commercial production. Contracts and licences are awarded for 25 to 35-year terms, subject to extensions for five to ten-year terms.
In most cases, the contract goes through a so-called 'start-up transition stage' that lasts up to 270 days, whereby the contractor prepares and files an environmental baseline and determines whether any existing wells and materials may be used in petroleum operations. Any pre-existing environmental damages are identified in this stage. The former operator (in most cases Pemex) assumes the liability of any pre-existing damages timely identified in the baseline study and acknowledged by the HSE regulator and CNH.
In all contracts, a so-called 'adjustment mechanism' is included to calculate considerations of the State and the contractor. The intent of this mechanism is for the State to receive a majority portion of any windfall profits due to high oil and gas prices.
There is a forced unitisation provision. The contractor is responsible for notifying the CNH and SENER in the case of shared reservoirs or fields. Although the contractor(s) or entitlement holders (ie, Pemex) propose the unitisation plan and agreement, ultimate approval of the plan rests with the government. SENER issued specific rules governing the creation of units and approval of unitisation agreements between operators.
Each contract provides the exploration and production periods, as well as the minimum work programme thresholds for the contractors or licencees. Extensions and modifications are granted on a case-by-case basis subject to CNH approval as long as they are in accordance with the applicable contracts and statute. The liability and risk are, generally speaking, the responsibility of the contractor or licencee. As discussed, contractors and licencees have the authority to withdraw from the contract areas at their discretion (nevertheless, the minimum work programmes shall be performed).
The export of hydrocarbons is not governed by the E&P contract and is rather subject to a permit from SENER. These export permits may be granted for one or 20 years, depending on the existence of long-term infrastructure commitments linked to such permit. Other than a mandatory minimum inventory for refined products that is applicable to traders, there is no domestic supply obligation under E&P contracts.
It is important to note that in the event of termination of the contracts, caused either by withdrawal or administrative/contractual termination by CNH as established under the contract, the materials and assets used in the hydrocarbon activities as well as the contractual areas shall be transferred to the state free of liens or encumbrances and without consideration to the contractor or licencee. As further discussed below, contractors are required to set aside funds in an abandonment trust for the abandonment phase.
Transfers of participating interest in a PSC or licence (ie, a farm-in or farm-out), require the prior approval of the CNH, where the CNH will verify financial capabilities (if dealing with a non-operator, and technical operational capabilities in the case of an operator). Generally speaking, for a term of five years as of the effective date of the contract, the farmee shall satisfy the same requirements included in the bidding guidelines originating the contract. Depending on the contract, there may be restrictions to replace the operator for a given term, and generally speaking, the operator may be required to have a minimum interest of the project (normally one-third of the project).
In cases where no change of control in the contractor (whether it is a single party or the consortium, collectively) or a change of operator will occur, the farmee and farmor, as applicable, are only required to notify the CNH on the relevant assignment of interests or equity changes. Note, however, that if the farmee (even in cases of non-operators) is a party who has not been prequalified in a bid process called by the CNH, the latter will require that such farmee undergoes a KYC process with the Financial Intelligence Unit (Unidad de Inteligencia Financiera) of the Ministry of Finance.
The CNH issued a set of guidelines and requirements to be satisfied in order to request and receive an approval to transfer a participating interest under an E&P contract. These rules provide specific guidance on the information and documents that the parties shall submit to request the authorisation of the CNH. These guidelines, however, have proved to have certain gaps with respect to assignments to parties that have not been previously prequalified or even participated in bid processes called by the CNH.
If prior consent from the CNH is required to undergo a change in control or otherwise assign a participating interest, the applicant is required to pay governmental fees of USD3,000 (if the farmee is prequalified) or USD25,000 (if the farmee is not prequalified).
In most cases, the remaining operator or consortium, as the case may be, is required to replace any performance bonds delivered to the CNH, amend the joint operating agreement filed to the CNH (if applicable) and request the CNH to amend the existing E&P contract to reflect the new participating interests of the members of the consortium. Furthermore, the farmee will be required to deliver a corporate guarantee issued by the ultimate parent company or an affiliate that satisfies the financial wherewithal establishes in the relevant contract, as appropriate.
If an E&P contract was executed with a single entity, in cases of farm-outs, the E&P contract is amended by using the consortium model available during the bid process.
For cases of indirect changes of control, the criteria on whether prior authorisation from the CNH is required is determined on a case-by-case basis and the provisions of each the E&P contract are taken into account. The clauses on assignment and change of control have varied significantly from the first bid process (2014) to the last bid process (2018).
There are no legal or regulatory restrictions on production rates. Private operators may produce hydrocarbons without restrictions on production rates to the extent that the operator is in compliance with technical aspects of the approved development plan. No OPEC quotas or other restrictions on production rates apply.
The Mexican market had an initial partial opening, allowing private participation in transportation, distribution, storage and marketing of natural gas, back in 1995. Since then, considerable gas transportation infrastructure has been developed by private players, mostly anchored by government offtakers (ie, the former power monopoly CFE, through long-term PPAs). Three LNG regasification terminals were also developed, similarly anchored. Despite this opening, the market for sales of natural gas continued to be vastly dominated by Pemex, who also controlled 90% of the pipeline system and offered customers a bundled service. With the 2014 reform, the rest of the midstream and downstream sector was fully liberalised, allowing private investment in transportation, distribution, storage, import, export, marketing and retail of all products, as well as refining and gas processing.
While currently Pemex continues to own the six existing refineries in Mexico, the system already allows for private refineries to be built, with the simple issuance of a permit from the Ministry of Energy. No bid process is required for such permit to be issued.
All midstream infrastructure may be built through the issuance of a permit from the CRE as well. Permits are issued upon evidence of project feasibility, including technical capabilities of the operator, consistency of the financial model (in most cases including the approval of a regulated rate), and approval of regulated terms of service and general terms of service. The permits issued by the CRE do not grant any type of exclusivity for the infrastructure to be built, and to that extent their issuance does not entail a bidding or other competitive process.
In general terms, all midstream infrastructure permitted by the CRE is subject to an open access principle, thus allowing any interested third party to book available capacity or participate in a project expansion. Services are to be provided under a regulated rate, which is approved by the CRE based on the capital and operating expenditures of the project, a reasonable rate of return and operating efficiencies, taking into consideration market benchmarks. The regulated rate is reviewed periodically by the CRE. Any expansions should be done through the launch of an open season to accommodate the potential needs of third parties.
Shippers are entitled to receive not unduly discriminatory treatment, including the granting of any special conditions given to other shippers under similar circumstances. A shipper that is not receiving due treatment, including rates, can resort to the CRE.
As a general rule, storage of liquids enjoys a lighter regulation with no rate regulation.
In the case of Pemex, as the incumbent operator of midstream assets for refined products, specific asymmetric regulation was issued by the CRE. While the initial auction process to award capacity did result in a few shippers securing capacity for pipelines and terminals in north-west Mexico, mandatory open seasons have not resulted in general access of private shippers to Pemex’s midstream infrastructure in the rest of the country, being this still a pending goal to achieve.
A permit for transportation, distribution or storage of gas or refined products (LPG/propane is treated as a refined product) is granted by the CRE upon approval of the conditions of the project. As discussed above, the permitting process does not entail any type of bid. It is possible that certain exceptional strategic projects on the natural gas side, to be launched by the National Center for Control of Gas (CENAGAS) may be awarded through a competitive bid.
The permitting process before the CRE/SENER is generally done online. Permits are issued to Mexican persons only; to apply for a permit, the application shall include, among other requirements, the payment of governmental fees, corporate documentation (ie, including a description of the corporate structure), description of the project, business plan and other specific requirements according to the activity. In some cases, the applicant is expected to provide extensive information on the corporate structure and business plans of the corporate group.
Holders of downstream licences, especially for imports of oil and gas products, are expected to secure other specific permits and authorisations from customs and the Ministry of Finance. An import permit granted by SENER does not, on its own, authorise the imports of products.
In addition to the above midstream permits, HSE permits from ASEA are required, including but not limited to the registration and authorisations of the HSE management system (SASISOPA), registration of insurance policies, among others.
Midstream and downstream projects are not subject to a special fiscal regime, in terms of payment of a special contribution or a government take. The facilities are subject to regular corporate income taxation of the permit holder. Given that permit-holders are, generally speaking, special purpose companies, they maintain a specific project financial model. For purposes of rate-making proceedings, the CRE would take into consideration the impact of federal income tax in the model and in the projected ROI, to ensure that in an efficient operation scenario the developer of the infrastructure can obtain an appropriate return.
Regular corporate income tax applies to downstream projects. In structuring the project and its financial model, the sponsors need to consider other local taxes, which mainly refer to property tax on the site or right of way, and statutory profit sharing for the employees in terms of labour laws. In cases where a site is acquired, the transfer of real estate may be subject to municipal real estate transfer taxes.
Due to the largely predominant position that Pemex had in the midstream and downstream sectors prior to the 2014 opening, the CRE has implemented 'asymmetric rules' to reduce Pemex’s share in the market and allow other competitors to come in. These asymmetric rules include regulated terms and conditions of sale, capped prices and other regulation applicable to Pemex only (capped prices are no longer applicable to natural gas sales). With respect to natural gas, the rules entail that Pemex is required to divest a material proportion of its portfolio of customers, to keep only a 30% of the market share in four years. As part of the reform, the natural gas pipelines formerly owned by Pemex were spun-off into a separate entity – CENAGAS – as an independent operator, to ensure access to any interested gas marketer. CENAGAS is undergoing an open season to allocate capacity in the system to shippers and to users directly.
In the motor fuels market, Pemex is forced to release any capacity booked in its own midstream infrastructure (owned and operated by Pemex’s logistics company) to the extent the relevant trader or distributor evidences to the CRE that is it has undertaken supply commitments, and satisfaction of other requirements.
Neither the Hydrocarbons Law nor the CRE as regulator require a local content programme for a permit-holder or developer of infrastructure. However, the Ministry of Economy is entitled, at any point, to issue rules encompassing the oil and gas industry as a whole (ie, including downstream activities).
Generally speaking, service providers are required to provide services on a firm and interruptible basis. Hence, shippers are entitled to reserve capacity on pipelines or terminals on a long-term basis, provided that it is effectively utilised. Capacity may be assigned to third parties in a secondary market.
Transportation companies are required to bear the risk of loss on the products while being transported, and are required to carry proper insurance for risks relating both to the product and operational casualties. Permit holders are required to ensure continuity of services to their customers, and therefore have to abide by special rules in order to terminate service.
Holders of midstream permits may withdraw from a permit to the extent no third-party rights are affected. Upon termination of a permit, whether for a voluntary withdrawal, revocation or otherwise, holders of these permits shall comply with the decommissioning and abandonment regulation issued by ASEA.
Mexico’s energy policy maker, SENER, issued the rules on minimum storage of refined products. This calls for a system similar to the 'strategic reserves' seen in other jurisdictions. The regulated parties, however, are traders and distributors of certain refined products (mainly diesel and gasolines). The rules on minimum storage, effective as of 2020, require a minimum inventory that will gradually escalate by 2025.
Private investors do not have condemnation/eminent domain rights. In securing rights of way, transportation companies are required to follow a very strict process of surface rights acquisition. The process is designed to provide certainty to the developers, but requires compliance with a number of steps, including formal appraisals, information to owners on the project specifics, validation of the contracts by a federal court, and the possibility of conciliation in cases of failure to reach agreement. Unlike in upstream projects, regulation by the Federal Executive is not clear on whether the creation of the so-called 'hydrocarbons legal easements' is allowed in case that developers and landowners fail to reach an agreement.
As noted above, generally speaking all facilities for transportation and storage of crude oil, gas and products are subject to an open access principle. The sizing of a project prior to its development requires in most cases the launching of a mandatory open season, in terms approved by the CRE and supervised by the regulator. Where facilities are financed through long-term contracts with an anchor shipper, such anchor shipper has the ability to secure long-term capacity on a 100% or such other capacity requirement it needs. With respect to storage of products, the open season may not be mandatory, and a more strict regulation may only be applied in specifically contemplated circumstances where the CRE determines such stronger intervention is warranted. The CRE may impose limitations on a private party’s participation in the market.
Producers, traders and end users of natural gas and products may only participate in the equity of terminal and storage companies with the prior approval of Mexico’s antitrust agency – COFECE – and the CRE.
The local market is now fully opened as a result of the market liberalisation, and any party is entitled to produce, import and sell products in the local market, obtaining a marketing permit from the CRE. Retail prices of both gasoline and diesel are now determined at free market prices in the entire territory.
The Hydrocarbons Law empowers SENER to grant export permits for hydrocarbons (ie, crude oil, gaseous and liquefied natural gas and condensates) and refined products. Through regulation, SENER determines which specific products will require an export permit – SENER may add or remove specific products in its sole discretion taking into account the country’s energy balance. These permits may be granted for periods of one year or 20 years. Until recently, the one-year permits did not require that the relevant applicant evidenced any specific infrastructure commitments or client/supplier agreements. However, the current government (2018-2024), is seeking to eliminate any type of speculation with these permits and therefore it has increased the one-year requirements to make them similar to that of the 20-year permit.
Other relevant authorisations required to export include the registrations before the customs authority. In the case of cross-border pipelines, an additional customs authorisation (issued by a special department of the customs authority) is required.
A permit-holder is entitled to transfer its permit to a third party, and therefore the project, with the approval of the CRE. The regulator reviews the qualifications of the assignee in terms of operational capabilities and financial wherewithal, and approves the amendment to the permit to include the assignee as its holder. Generally, the transfer process is done online and requires the payment of governmental fees and may take up to 90 business days to be finally approved.
But for isolated exceptions in jet fuel supply within airports and bunker supply, there are no restrictions from the foreign investment law perspective to invest in the energy sector in Mexico. Foreign investors conducting a project in Mexico may enjoy the benefits of the investment protection treaties that Mexico has with their respective countries of origin. Mexico has the broadest array of bilateral investment protection treaties worldwide, including with most major economies. These generally cover investor-state arbitration, protection against expropriation, including creeping or de facto expropriation.
Resolution of disputes under the E&P contracts is subject to international commercial arbitration. E&P contracts contain a so-called 'tax-balancing clause' that does not amount to be a standard stabilisation clause in other jurisdictions.
As part of the 2014 energy reform, the Mexican Congress created a specialised agency to deal with environmental and health and safety matters in the oil and gas industry: the Agency for Environment, Health and Safety for the Hydrocarbons Industry (Agencia de Seguridad Industrial y Protección al Ambiente del Sector Hidrocarburos), known by its acronym, ASEA (see https://www.gob.mx/asea). The ASEA is entrusted with overseeing compliance and with the issuance of environmental permits for oil and gas projects, as well as official technical specifications of mandatory applicability in the industry.
As to legal framework, the main statutory bodies are the following.
To date, ASEA has issued HSE rules for E&P projects, unconventional projects, and insurance for E&P activities, among others.
To conduct a petroleum project, a number of environmental approvals are required, the following being critical.
Considering the maturity of certain projects in Mexico, E&P contracts contain specific rules for HSE authorisations and permits, as well as the characterisation, approval and acknowledgment of pre-existing damages. Furthermore, both upstream and downstream operators are required to prepare and comply with a plan to prevent and control methane gas emissions.
Offshore activities are regulated by the so-called General Administrative Provisions on Guidelines for Industrial Safety, Operational Safety and Environmental Protection, applicable to Hydrocarbons Recognition and Superficial Exploration, Exploration and Extraction (the Upstream HSE Guidelines). These set forth specific obligations that will specifically apply, respectively, for reconnaissance and superficial exploration activities and exploration and extraction activities. In addition to the general obligations mentioned above, regulated parties shall file before ASEA several notices, including those regarding: Commencement of Operations Notice, Change of Operations Notice; Dismantling and Abandonment Authorisation Application. Also, they must verify the mechanical integrity of their facilities during design, construction, operation, maintenance, operational closure, decommissioning and abandonment; prepare and keep documentation on several technical and operational specifications such as the drilling fluids management and the system to mitigate risks from the recollection and mobilisation of hydrocarbons and document certain events and circumstances such as sighting of species, location of data acquisition sites, among other operational specifications and measures.
Operators are also required to prepare and register an HSE management system known as SASISOPA. Likewise, before the implementation of this system in any project, the operator is required to obtain ASEA’s specific authorisation.
Furthermore, operators are required to maintain proper insurance coverage. The ASEA has issued the General Administrative Provisions on Guidelines that establish the rules for insurance policies for exploration and extraction of hydrocarbons and the treatment, refining and processing of crude oil and natural gas. Under these rules, operators are required to register the procurement, renewal and amendments to mandatory insurance policies.
As a first obligation, the HSE management system (SASISOPA) of the regulated parties (operators) must include the decommission phase, which is implemented and evaluated by a specific area of the company. Other obligations are imposed for the different aspects of the decommissioning phase, including activities prior, during and after the phase:
The Upstream HSE Guidelines establish obligations and requirements for abandonment activities, such as the obtainment of an authorisation prior to performing any abandonment activity.
Operators and non-operators are jointly and severally liable for all obligations under E&P contracts executed with the Mexican State. For that reason, non-operators are liable for any decommissioning and abandonment obligations. Moreover, these E&P contracts provide for an abandonment trust that is funded by the contractor throughout the effective term; any shortage of funds is covered by the contractor(s). Until abandonment obligations are satisfied, the CNH may hold on to the corporate guarantees provided by affiliates of the contractor.
As indicated before, Pemex, as the sole oil and gas operator more than 70 years, assumes any identified pre-existing damages by new operators. This may include pending decommissioning and abandonment operations and activities.
Mexico has adopted the major international treaties on climate change, and has also adopted a General Law on Climate Change (Ley General de Cambio Climático, LGCC). The LGCC regulates greenhouse gas emissions to achieve the stabilisation of their concentration in the atmosphere at a level that prevents anthropogenic interferences in the climate system. It regulates the hydrocarbons sector, granting power and authority to the federal government to establish mechanisms that promote the prevention of gas emissions in the extraction, transportation, processing and use of hydrocarbons. Specific regulations in the environmental laws implement a federal registry of pollutants and releases and a transfer register, and regulations on atmosphere pollution require oil and gas industry players to install controlling equipment, adopt reduction mechanisms and maintain pollution inventories, among other obligations.
In connection with the above mandate, in November 2018, ASEA issued the General Administrative Provisions establishing the guidelines to prevent and the comprehensive control of methane emissions in the hydrocarbons sector. These guidelines effectively take into account international commitments of Mexico such as the Paris Agreement. For new facilities, operators are required to prepare and comply with a prevention and comprehensive control programme for methane emissions. Existing facilities are required to establish technically feasible reduction goals.
In addition to the above, under the Hydrocarbons Law, the CNH has authority to regulate flaring and venting of natural gas into the environment in upstream projects. Since the 2014 energy reform, the CNH has issued specific regulation on the subject matter.
In accordance with the Hydrocarbons Law, the oil and gas industry is of exclusive federal jurisdiction. Thus, only the federal government may issue technical and regulatory provisions on the subject matter, including those related to the sustainable developments, ecological equilibrium and environmental protection.
Despite the foregoing, local and municipal government often require construction, operation and other types of permits/licences which issuance may delay onshore projects. Recently, Mexico’s Supreme Court issued a ruling which may open the door to local and municipal government interference with oil and gas activities. However, because the ruling itself was issued in a different context (which does not bear the 'strategic nature' cloak under the Mexican Constitution), we do not believe that any limitation or issuance of taxes by local/municipal government would limit or otherwise interfere with oil and gas development.
Unconventional resources are developed under the same scheme as conventional resources (ie, through licence agreements or PSCs granted by the CNH), with the exception of coal-bed methane gas which is associated with coal production and is exploited through a mechanism associated with the relevant mining concession.
Also, a separate set of HSE guidelines for unconventional resources was issued by ASEA. These are applicable to exploration and extraction of onshore unconventional resources. The federal water regulator (CONAGUA) has issued a set of guidelines related to conservation of national waters in unconventional E&P activities.
While current laws and regulations allow operators to exploit unconventional resources, the current federal administration has publicly stated that no unconventional development of oil and gas resources (using hydraulic fracturing or an exploitation technique) will be allowed during this administration (2018-2024). Very recently, Mexico’s President publicly criticised the approval of a development plan for unconventional resources submitted by Pemex to the CNH. This may evolve in the mid-term as Mexico seeks to increase its production platform and be less dependent on imported natural gas.
From the regulatory perspective, LNG terminals are treated as gas storage terminals. The three existing LNG regasification terminals were built in Mexico prior to the 2014 energy reform. The new framework does contemplate a specific additional permit for liquefaction, but is to a great extent ancillary to the storage permit. Imports and exports of LNG are treated as those of natural gas and do not enjoy any special treatment. Neither do they have any special restriction.
Under Mexico’s natural gas minimum storage rules issued by SENER, LNG terminals are considered for purposes of determining the scope of CENAGAS’ expected natural gas storage projects.
Unlike most oil and gas jurisdictions that also have one or more national oil company(ies), Mexico’s production-sharing contract model, or any other E&P contract for that matter, does not require the participation of the national oil company (NOC) in oil and gas projects. Generally speaking, Pemex, the NOC, is treated like any other private party when participating in the rounds to award E&P contracts (although it does have its own scheme of entitlements for the award of areas to the NOC; these entitlements are expected to be used increasingly in the new federal administration – at least in the short term – while upstream rounds resume). Another key difference is Pemex’s ability to transform its entitlements to E&P contracts while farming out the project to IOCs. The selection of Pemex’s farmees (partners) is subject to the scrutiny of the upstream regulator; this achieves a level of transparency never before seen in upstream transactions with IOCs.
Another important aspect of Mexico’s E&P contracts is the so-called 'administrative rescission' which essentially allows the government to terminate a contract upon the occurrence of a 'serious' breach. Private operators may not resort to arbitration for any matter arising from or related to administrative rescission, their sole remedy is to challenge this decision before Mexican federal courts. If the operator prevails in court, the determination of damages is subject to arbitration.
On 1 December 2018, the left-wing presidential candidate Andres Manuel Lopez Obrador took office. Although he ran on a political campaign that was highly critical of the 2014 energy reform, so far, no major changes to laws and regulation have occurred, and the administration has pledged not to amend the reform framework. There have been attempts in Congress, however, to amend the Law of Petroleos Mexicanos and establish a nationwide ban on hydraulic fracturing activities, but those bills were not successful. Despite the fact that no legislative or major regulatory changes were introduced over the past year, the current government has deferred all bid rounds for unconventional blocks, the Pemex 'farm-outs' conducted by the CNH, and it has likewise instructed Pemex to desist from the migration process of multiple service contracts to E&P contracts.
With respect to regulation, relevant changes include:
Furthermore, on 1 May 2019, the Mexican Congress passed major amendments to the Federal Labor Law (Ley Federal del Trabajo) on union and collective bargaining agreements. This labour reform aims to provide enhanced participation to unions to more effectively represent the interest of employees.
Most of the commissioners of the CRE (ie, Mexico’s midstream regulator) resigned following the election and inauguration of the new federal administration. To replace these commissioners, the President nominated candidates who have openly questioned the regulation established by the CRE in the past – particularly, the asymmetric regulation imposed on Pemex as the predominant player in the market. For this reason, we expect that midstream regulation in Mexico may change significantly during the next year.
The current administration has informally committed to not introduce major changes to the existing legal framework inherited from the 2014 energy reform (except for asymmetric regulation imposed on Pemex). At the same time, however, it has promised that no oil and gas blocks will be awarded until the E&P contracts awarded since 2015 start to yield the 'promised' production results. Of relevance, the first private offshore operator commenced production in the Gulf of Mexico in July 2019.