Contributed By Dentons Lopez Velarde, S.C
Like many other jurisdictions, 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.
The Hydrocarbons Law (enacted in 2014 to restructure the market) 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 or “CNH”) – see www.gob.mx/cnh; the Energy Regulatory Commission (Comisión Reguladora de Energía or “CRE”) – see www.gob.mx/cre – is entrusted with the regulation of midstream, including transportation, distribution, storage and marketing of both hydrocarbons and refined products. The Ministry of Energy (Secretaría de Energía) – see www.gob.mx/sener– which is mostly the policy-maker and the co-ordinator with respect to energy planning, maintains regulatory powers on the side of refining (including permitting for new refineries and for the existing Pemex refineries) gas processing, and on the imports and exports side (both for hydrocarbons and products), given its role in safeguarding national energy security.
In addition to such a structure, the 2014 reform opted for an additional bifurcation with respect to 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 predominant operator, on the upstream side, and as an additional player (with market predominance as well) for the remaining 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 out a 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 options. 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 approximately two thirds of those in which it was undertaking 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 of the following statutes and regulations.
In addition to the foregoing, note that the statutory framework provides both CRE and CNH 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 four years. No major overhaul to any of these instruments is expected.
A private operator may conduct the activities of exploration and extraction of hydrocarbons (ie, explore for, develop and produce) through an E&P contract 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, a combination of the above, 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 exploit the hydrocarbons in the area upon payment of consideration to the state. 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 guarantee, in the form of a bond or letter of credit, and a corporate guarantee 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).
Other than standard permits and authorisation for E&P projects, such as HSE 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 in Mexico, whether to trader or end user, the operator requires a trading permit issued by the midstream regulator, CRE.
Pursuant to the Hydrocarbons Revenues Law, under a licence contract scheme, the State shall receive:
Under profit and production sharing contracts, the State shall receive:
The above-mentioned monies shall be paid to the Mexican Petroleum Fund (Fondo Mexicano del Petróleo) for their management and distribution under the 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; 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 – 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 either to “carry” the investment required for Pemex or to 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 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. The mechanism to reach the above-mentioned goal is established by the Ministry of Economy, whereby the following factors shall be considered:
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 licensees 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 licensee or contractor carries the risk of the 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 licensees 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 licensees/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).
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 licensee 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 percentage of the revenues generated and recovery is contingent upon commercial production. Contracts and licences are awarded for 25-35 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 identified in a timely manner 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 Ministry of Energy 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. Recently, the Ministry of Energy 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 licensees. 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 licensee. As discussed, contractors and licensees have the authority to withdraw from the contract areas at their discretion (nevertheless, the minimum work programmes shall be performed).
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 licensee. 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 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 farmeeshall 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 in the project (normally one third of the project).
In cases where no change of control in the contractor 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.
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.
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 a 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 executed 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 lighter regulation with no rate regulation.
A permit for transportation, distribution or storage of gas or 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 Centre for Control of Gas (CENAGAS), may be awarded through a competitive bid. As an important part of this mandate, CENAGAS is expected to launch major natural gas underground storage projects in the course of this year.
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 (including a description of the corporate structure), description of the project, a 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.
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 return on investment (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 consist of 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 regulations applicable to Pemex only (eg, 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, retaining only 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 it has undertaken supply commitments, and satisfaction of other requirements.
Neither the Hydrocarbons Law nor the CRE as regulator requires 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 uninterrupted 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. Downstream permits also allow pipeline and terminal companies to provide spot services.
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 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.
Recently, 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 until 2020, require a minimum inventory, but this will gradually escalate up to ten days of inventory by 2022, and up to 15 days 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 does not allow the creation of so-called “hydrocarbons legal easements” if the 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, that anchor shipper has the ability to secure long-term capacity of 100%, or such other capacity as it requires. 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 open, as a result of the market liberalisation; any party is now 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.
Recently, the federal government confirmed the repeal of a certain federal regulation that prevented private parties from participating in storage, distribution and supply of refined products activities at Mexican airports. Thus, the exclusivity held by Aeropuertos y Servicios Auxiliares (ASA) under such regulation has been lifted.
A permit-holder is entitled to transfer its permit – and therefore the project – to a third party, 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 executed online; it requires the payment of governmental fees and may take up to 90 business days to be finally approved.
Except for isolated exceptions in jet fuel supply within airports and in bunker supply, from the foreign investment law perspective there are no restrictions to investing 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 and 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, or"ASEA"). This agency 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 the legal framework, the main statutory bodies are the following.
To date, ASEA has issued health and safety 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, but the following are critical:
Considering the maturity of certain projects in Mexico, E&P contracts contain specific rules for health and safety authorisations and permits, as well as the characterisation, approval and acknowledgment of pre-existing damages.
Offshore activities are regulated by the General Administrative Provisions on Guidelines for Industrial Safety, Operational Safety and Environmental Protection, applicable to Hydrocarbons Recognition and Superficial Exploration, Exploration and Extraction (Disposiciones administrativas de carácter general que establecen los lineamientos en materia de Seguridad Industrial, Seguridad Operativa y protección al medio ambiente para realizar las actividades de Reconocimiento y Exploración Superficial, Exploración y Extracción de Hidrocarburos, or the “Upstream HSE Guidelines”). These set forth specific obligations that will apply, respectively, for recognition 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 a Commencement of Operations Notice, a Change of Operations Notice, and a Dismantling and Abandonment Authorisation Application. Also, they must verify the mechanical integrity of their facilities during design, construction, operation, maintenance, operational closure, dismantling and abandonment; furthermore, they must 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 the sighting of organic species, and the location of data acquisition sites, among other operational specifications and measures.
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 (Disposiciones administrativas de carácter general que establecen las reglas para el requerimiento mínimo de seguros a los Regulados que lleven a cabo obras o actividades de exploración y extracción de hidrocarburos, tratamiento y refinación de petróleo y procesamiento de gas natural).
As a first obligation, the HSE management system 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. Until abandonment obligations are satisfied, the CNH may hold on to the corporate guarantees provided by affiliates of the contractor.
As indicated above, Pemex, as the sole oil and gas operator for 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, or “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, releases and a transfer register; regulations on atmospheric pollution require oil and gas industry players to install controlling equipment, adopt reduction mechanisms and maintain pollution inventories, among other obligations.
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.
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.
A separate set of HSE guidelines for unconventional resources was also 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.
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 restrictions.
Under Mexico’s natural gas minimum storage rules, issued by SENER, LNG terminals are considered for the 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 companies, Mexico’s production sharing contract (PSC) 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 E&P contract scheme. Another key difference is Pemex’s ability to transform its entitlements to E&P contracts while farming out the project to OICs. 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.
Over the last year, there have been many developments in the industry. The government finally launched the first tender for unconventional E&P projects in northern Mexico – these are licence contracts for exploration and production. Likewise, SENER issued the long-awaited guidelines on unitisation of reservoirs (including the rules related to unit orders and unit agreements) and the guidelines to determine the percentage of revenues that landowners are entitled to receive from E&P onshore projects.
Just recently, after years of public consultation and debate, SENER finally issued a key piece of regulation for the oil and gas industry. These are the general administrative provisions on social impact assessment in the energy sector. Essentially, these rules establish the elements that private parties shall be required to comply with in preparing and filing social impact assessments, as well as the process undertaken by SENER in such review. This assessment is independent and not to be confused with the social impact study undertaken by the government.
In matters of HSE, the ASEA has continued to issue rules for activities of the hydrocarbons value chain. CONAGUA, the water regulator, in turn issued rules related to water use in unconventional E&P projects.
Early in 2018, Mexico adhered to the Convention on the Settlement of Investment Disputes between States and Nationals of other States (the “ICSID Convention”). Once approved by Congress, foreign investments in Mexico will be vested of additional legal certainty, mainly on the enforcement of awards derived from investment disputes and recourses available for annulment, interpretation and revision of the same; despite not being part of the ICSID Convention before, Mexico has been one of the most active countries in investment disputes, with more than a dozen cases conducted according to either the ICSID Additional Facility Rules or the rules of the United Nations Commission on International Trade Law, as incorporated by reference in the Bilateral Investment Treaties (BITs) executed by Mexico thus far. We expect this will have a major impact on the oil and gas industry in Mexico, specifically for the exploration and extraction activities currently developed by IOCs. Although the E&P contracts entered into by the Mexican State provide for commercial arbitration as a dispute resolution mechanism, all the acts of authority (including administrative rescission cases) may fall within the scope of application of the ICSID Convention, based on the standard of protection established in the relevant bilateral investment treaties.
To date, no amendments, other than an amendment to the Hydrocarbons Law’s saving provisions aimed at expediting the liberalisation of motor fuel imports and determination of prices, has taken place.
Following the results of the latest Mexican election, a coalition led by the left-wing party Morena (the political party that nominated the President-Elect), will hold a majority in both houses of the federal Congress and most local congresses. This means that Mexico’s left wing will control whether any changes to energy-related federal statutes are introduced. While the President-Elect takes office on 1 December 2018, Congress will do so on September 1st.
Although the President-Elect promised substantial changes to the still very young energy reform, in the final months of the campaign, these promises were toned down. Still, we can expect that the new administration’s focus will be set on the E&P sector; undertaking a “review” of existing E&P contracts and calling for the possible suspension or rescheduling of the ongoing oil and gas rounds. The transition team has insisted that the scope of the aforementioned “review” will focus on transparency issues and unconscionable terms and conditions of existing E&P contracts. These is not seen by the industry as a material threat given the conditions of transparency under which the bids were held generally. The President Elect has repeatedly stated that the new administration will uphold and abide by the existing contracts.
On the other hand, one may expect a restrengthening of both Pemex and Comisión Federal de Electricidad (Mexico’s power utility) and that they will be granted additional budget to promote government investment without relying on joint ventures. More specifically, the new administration is expected to invest heavily in revamping existing refineries and developing additional refining capacity. Further, the federal government is likely to push energy regulators to remove any “asymmetric regulation” imposed to Pemex in an attempt to regain any market presence Pemex may have lost in the last couple of years.
During the presidential transition stage (2 July to 1 December 2018), IOCs and developers can expect a slow-down in E&P activity in Mexico—more likely than not, no additional oil and gas rounds will be launched by the Mexican government.