Policy and Targets
Background and the Role of Reductions in Meeting Environmental and Economic Objectives
Between 2012 and 2021, oil production in Mexico fell by one-third, but the volume of gas flared increased by one-third and the flaring intensity more than doubled. While the volume of gas flared shows an upward trend since 2018, oil production remained largely stable, leading to a corresponding increase in flaring intensity. There were 115 individual flare sites in the last flare count, conducted in 2019.
Gas flaring volume and intensity in Mexico, 2012–21
In 2016, Mexico endorsed the Zero Routine Flaring by 2030 initiative (World Bank, n.d. Mexico also participates in the Global Methane Initiative (n.d.) and the Climate and Clean Air Coalition (n.d.). In its updated NDC submitted to the UNFCCC in December 2020, Mexico committed to unconditional contributions of a 22 percent reduction in GHG emissions and a 51 percent reduction in black carbon by 2030 compared with a business-as-usual scenario.
In 2016, the National Hydrocarbons Commission (Comisión Nacional de Hidrocarburos [CNH]) set guidelines for the national oil company Petróleos Mexicanos (Pemex) to reduce flaring. The guidelines were expected to be enforced over the coming years. However, the upstream sector’s lack of financial resources and investment priorities have prevented major projects from being implemented.
In June 2016, Mexico joined the United States and Canada in calling for a 40–45 percent reduction in methane emissions from their oil and gas sectors by 2025. In November 2018, Mexico’s Agency for Safety, Energy and Environment (Agencia de Seguridad, Energía y Ambiente [ASEA]) released the Guidelines for the Prevention and Comprehensive Control of Methane Emissions from the Hydrocarbons Sector, DOF: 06/11/2018, to meet this target. ASEA’s guidelines require new and existing facilities across the value chain to meet facility-wide emission limits.
Targets and Limits
Article 14 of the CNH Technical Provisions for the Use of Associated Natural Gas in the Exploration and Production of Hydrocarbons, DOF: 07/01/2016 specifies the methodologies and criteria for operators to structure their associated gas utilization programs and targets. For exploration, the operator indicates the volumes of associated gas that can be utilized given existing technologies, infrastructure, and knowledge of the fields to be explored. The CNH then reviews the associated gas utilization program to establish the targets to be applied throughout the exploration stage. For production, the operator needs to achieve and maintain an annual utilization rate for associated gas of 98 percent. The target must be reached within three years of the start of operations. The operator should detail the actions and investments needed to achieve and maintain the target annually. The CNH reviews the proposed targets and utilization program, and where appropriate, modifies and establishes the final targets to be implemented throughout the production stage.
Article 15 permits operators to propose an adjusted gas utilization program to the CNH if field conditions make it uneconomic to reach the authorized targets after the initial three-year period. The CNH may adjust the initial target to maximize crude oil and natural gas production over the long term under economically viable conditions.
Legal, Regulatory Framework, and Contractual rights
Primary and Secondary Legislation and Regulation
In 2008, the Mexican Congress issued the Law of the National Hydrocarbon Commission, DOF: 11/28/2008. Article 3 assigns responsibility for regulating the use of natural gas to minimize gas flaring and venting in oil and gas exploration and production to the CNH. Article 43 of the Hydrocarbons Law, 2014, affirms the CNH’s responsibility for overseeing the use of associated natural gas.
Mexico’s oil and gas sector is also subject to the General Law on Ecological Equilibrium and Environmental Protection, 2021, and other technical environmental standards issued by the Ministry of Environment (Secretaría de Medio Ambiente y Recursos Naturales [SEMARNAT]) and ASEA. They may impose additional conditions on flaring and venting as part of the approval of the environmental license for upstream petroleum activities.
ASEA Guidelines for the Prevention and Comprehensive Control of Methane Emissions from the Hydrocarbons Sector, issued as part of Mexico’s international climate commitments, prohibit gas venting, except in emergencies.
Gas flaring is a matter of national jurisdiction. Article 95 of the Hydrocarbons Law, 2014, vests the regulatory oversight of the oil and gas sector exclusively in the federal government.
Associated Gas Ownership
Article 1 of the Hydrocarbons Law, 2014, vests the “perpetual” ownership of subsoil oil and gas in the state. Article 4 of the CNH Technical Provisions for the Use of Associated Natural Gas in the Exploration and Production of Hydrocarbons states that associated natural gas is the property of the state and that its production is subject to the terms established in the Hydrocarbons Law, 2014, assignments, and contracts. CNH technical provisions regulate the use of natural gas.
According to the Hydrocarbons Income Act, 2014, PSCs and license contracts, the two main forms of agreements in Mexico, regulate the ownership of extracted oil and gas. Under PSCs, title to a part of the production is transferred to the contractor in the form of cost and profit oil and gas. Under a license contract, the contractor owns all extracted oil and gas and can sell its share of production on the market. The gas price (often linked to a formula) can be established in the contract or determined by the Energy Regulatory Commission (Comisión Reguladora de Energía), which sets the gas price at the point the gas enters the Integrated National Transportation and Storage System.
Regulatory Governance and Organization
Article 3 of the Law of the National Hydrocarbon Commission establishes the CNH as the regulator of oil and gas exploration and production. The CNH is under the Secretariat of Energy (Secretaría de Energía [SENER]). The CNH’s responsibilities include regulating the use of associated natural gas and defining technical and operational standards to maximize the recovery and the value of hydrocarbons in the long term while ensuring the minimization of gas flaring and venting. ASEA, which reports to SEMARNAT, oversees the oil and gas sector’s industrial safety, operational safety, and environmental protection.
Regulatory Mandates and Responsibilities
The mechanisms for controlling and permitting flaring and venting are within the remit of the CNH. In carrying out its role, the CNH draws on the hydrocarbon policy, the National Energy Strategy, and the programs issued by SENER, the head of which is the chair of Pemex’s board of directors. Historically, Pemex was the only gas producer in Mexico. The CNH Technical Provisions for the Use of Associated Natural Gas in the Exploration and Production of Hydrocarbons prescribe new methods for measuring gas flaring and venting and attempt to promote gas utilization beyond re-injection.
ASEA can impose conditions related to flaring and venting when issuing an environmental license. These conditions focus on preventing and mitigating GHG emissions under Articles 8 and 12 of the Regulation of the General Law of Climatic Change (RLGCC Regulation), 2014. ASEA Law, 2014, extends the need for an EIA to construct and operate facilities across the oil and gas value chain, including production, processing, transportation, refining, and petrochemicals. ASEA can mandate operators to fix sources of polluting emissions, including those in the oil and gas sector. The law also provides for interinstitutional coordination. Additionally, every contractor is required to submit an EIA and obtain approval from ASEA, granted in an environmental license, before initiating operations.
Monitoring and Enforcement
Articles 1–4 of the Law of the National Hydrocarbon Commission empower the CNH to implement the measures necessary to monitor and audit the oil and gas industry. The CNH can supervise, verify, monitor, and, where appropriate, certify compliance with the law’s provisions. Sanctions can be applied in line with the Hydrocarbons Law, 2014. The CNH may also accredit third parties to supervise, inspect, and verify activities.
Flaring or Venting without Prior Approval
Article 4 of the CNH Technical Provisions for the Use of Associated Natural Gas in the Exploration and Production of Hydrocarbons states that gas venting is allowed only for safety reasons in emergency cases. Article 6 specifies that the flaring of associated natural gas is allowed during well testing (as long as it is included in the exploration or development plans approved by the CNH), in situations that pose safety threats, and when productive use is not viable (as shown by the technical-economic analysis required in Article 11 and approved by the CNH). Article 21 requires operators to notify the Commission when they have carried out flaring during well tests. The notification should be sent within 48 hours of the test. If emergency gas venting occurs, ASEA must be informed of the volume vented. The volume of gas flared or vented must adhere to the provisions issued by the CNH based on the gas utilization program. The CNH website includes an example of the implementation experience in the Tepetate field.
Authorized Flaring or Venting
According to Article 10 of the CNH Technical Provisions for the Use of Associated Natural Gas in the Exploration and Production of Hydrocarbons, the authorization to flare associated gas is included in the exploration or development plan’s approval according to detailed instructions in Articles 14 and 15. Articles 18–27 of the Regulation of the General Law of Ecological Balance and Environmental Protection in the Field of Prevention and Control of Atmosphere Pollution, 2014, require certain stationary sources—those that emit or may emit odors, gases, solid particles, or liquid particles into the atmosphere—to obtain operating licenses, which SEMARNAT issues by for an indefinite term, and outline the requirements and steps involved in the license application. For the oil and gas sector, the license application is made to ASEA.
Article 44 of the Hydrocarbons Law, 2014 requires oil and gas producers to seek approval from the CNH for exploration and development plans. The CNH Technical Provisions for the Use of Associated Natural Gas in the Exploration and Production of Hydrocarbons require the treatment of associated natural gas, including flaring, to be specified in exploration and development plans. According to Article 5 of the CNH Technical Provisions, the operator may utilize the associated natural gas for the needs of the operation such as fuel for turbines, or pneumatic pumping or other lifting systems that require gas injection. Alternatively, gas can be conserved through re-injection or transferred to another contract area or third party via a commercial transaction.
Article 10 requires the operator to submit to the CNH a program to use associated gas as part of the development plan for each assignment and contract containing the following information:
- a technical-economic analysis
- the volume of associated gas to be used
- a description of the actions and investments for the use, conservation, transfer, and, when necessary, flaring, including a general description of facilities and equipment dedicated to flaring or its use, identifying its location, available measurement systems, and maintenance procedures
- a schedule of well tests to be performed
- the operational performance indicators, which must detail the name and formula of the indicator, frequency of measurement, targets, and measurement parameters.
The programs must include month-by-month forecasts for associated gas use during the first three years and annual forecasts thereafter. The CNH website provides examples of development plans that include approved associated gas use programs. One example is contract CNH-M4-ÉBANO/2018.
Article 6 of the CNH Technical Provisions for the Use of Associated Natural Gas in the Exploration and Production of Hydrocarbons allows flaring only when technical and economic analysis shows that it is the only viable option. Article 11 requires operators to conduct a technical and economic analysis to develop alternatives for the use of associated gas, to be carried out in line with the target established and the criteria detailed in Articles 4 and 5 of the Technical Provisions. The analysis should consider the composition and volume of the gas; the proximity of the processing, transportation, and distribution infrastructure; the value of the gas; and the necessary investments to utilize it. The guidelines contain case-by-case evaluation elements. The regulator and operator are expected to work together to find the best solution for a particular field. Any modifications operators propose to their associated natural gas utilization program need to be supplemented with an update of the technical and economic analysis, justifying the actions, alternatives, and where appropriate, a new target to be adopted.
Article 7 requires operators to maintain the financial resources to cover any damages caused by flaring. The allowed amounts of flaring are determined according to the Hydrocarbons Law, 2014 or the project-related contracts. The CNH website provides examples of implementation experience. Two examples are the Tierra Blanca and the Muro fields.
Between 2007 and 2009, Pemex’s gas flaring and venting levels increased substantially, triggering efforts to reduce emissions, particularly in the Northwest Marine Region (in the Cantarell deposit). In December 2009, the CNH promulgated Resolution CNH. 06.001/09, 2009, prescribing procedures and techniques to reduce and prevent gas flaring and venting in hydrocarbon exploration and production. Under these guidelines, Pemex was required to submit to the CNH for its approval oil impact statements for its new projects using the most appropriate technologies. Noncompliance with these guidelines triggered sanctions. The regulation is mainly performance-based and requires Pemex to identify and evaluate feasible options for developing new facilities and increasing associated gas utilization. The guidelines expressly require Pemex to provide an economic evaluation and implementation strategy for re-injection and on-site power generation using the cost of utilization treatment equipment as a factor of analysis.
Measurement and Reporting
Measurement and Reporting Requirements
Article 16 of the CNH Technical Provisions for the Use of Associated Natural Gas in the Exploration and Production of Hydrocarbons requires the operator to follow the standards established in the CNH Technical Guidelines in Hydrocarbon Measurement, 2015, for measuring and reporting the volumes of the associated natural gas used. These guidelines were subsequently updated in February 2016, August 2016, and December 2017.
Articles 23 and 24 of the CNH Technical Provisions for the Use of Associated Natural Gas in the Exploration and Production of Hydrocarbons require the operator to provide quarterly reporting of progress in implementing the associated gas use program. The report should follow the CNH format outline and include the volumes of associated gas used, justification for any deviations from the gas use program, and a summary of unscheduled events that had resulted in gas flaring. Article 25 requires the CNH to review the quarterly reports within 15 business days of receipt and authorizes the CNH to request additional information from the operator. Article 26 requires operators to report monthly the associated natural gas balance per the provisions of the CNH Technical Guidelines in Hydrocarbon Measurement. The information should be submitted following a format found in the CNH Technical Provisions for the Use of Associated Natural Gas in the Exploration and Production of Hydrocarbons (CNH.17.005/2019).
The ASEA Guidelines for the Prevention and Comprehensive Control of Methane Emissions from the Hydrocarbons Sector requires operators to identify the source and quantify the volume of methane emissions. The information must be reported annually.
Measurement Frequency and Methods
Article 10 of the CNH Technical Guidelines in Hydrocarbon Measurement, 2015, requires daily and monthly reporting of oil and gas measurements to the CNH for the following:
- the daily volume and quality of production, disaggregating the average output of oil, condensate, gas, and water
- the volume of hydrocarbons extracted per oilfield, if applicable
- the hydrocarbon balance from the well and, if applicable, from the oilfield to the measurement point
- the volume of natural gas used or flared
- the volume of natural gas vented in exceptional circumstances.
Article 16 of the CNH Technical Provisions for the Use of Associated Natural Gas in the Exploration and Production of Hydrocarbons requires that, for the measurement and reporting of associated natural gas volumes, operators consider the conditions of pressure and temperature as well as the standards in the existing measurement guidelines issued by the CNH. Article 24 states that the program is monitored through quarterly reports provided by the operator to the CNH. These quarterly reports are available on the CNH’s website.
Article 25 of the CNH Technical Guidelines in Hydrocarbon Measurement, 2015, requires the operator to measure and report to the CNH the volume of natural gas produced, used, re-injected, flared, and vented. Natural gas used should be measured directly through flow meters. The uncertainty levels for measuring natural gas from flaring may not exceed 5 percent. However, when the use and re-injection have fiscal or commercial implications, the measurement uncertainty levels are limited to 1 percent. If natural gas is vented for exceptional reasons, the operator should report such venting to the CNH. In all cases, the chemical composition of the gas should be determined, either by sampling and laboratory analysis or by using installed continuous analyzers.
The CNH Technical Guidelines in Hydrocarbon Measurement, 2015, require an indirect gas volume estimation to be made in accordance with gas-to-oil ratio accounting or by using a system balance or simulation. According to the ASEA Guidelines for the Prevention and Comprehensive Control of Methane Emissions from the Hydrocarbons Sector, the volumes of methane emitted may be calculated or measured, but in all cases, the operator must provide a technical justification for the choice of the methodology applied. If quantification involves calculations, it may be based on the following:
- material balance;
- mathematical models
- engineering calculations
- equipment emission factors established by the manufacturer.
Article 33 of the CNH Technical Provisions for the Use of Associated Natural Gas in the Exploration and Production of Hydrocarbons requires the operator to make available to the CNH at all times any information and documents related to the use of associated gas, including the equipment and instruments used. This information should be retained for five years from the effective date of the assignment or the corresponding contract. Article 21 of ASEA’s Guidelines for the Prevention and Comprehensive Control of Methane Emissions from the Hydrocarbons Sector requires the maintenance of records related to methane-emitting components and activities at facilities for five years.
Data Compilation and Publishing
The CNH compiles data submitted by operators on flaring and venting for public disclosure on the website of the CNH’s Hydrocarbon Information System. Information on gas use demonstrates the rising volumes of gas that have not been used in operations or marketed in recent years. Since late 2020, the percentage of gas used fell below 90 percent, well below the 98 percent target (see the Targets and Limits section of this case study).
Fines, Penalties, and Sanctions
Article 7 of the CNH Technical Provisions for the Use of Associated Natural Gas in the Exploration and Production of Hydrocarbons states that flaring of associated gas, a nonrenewable resource, outside of the approved utilization program would cause an economic loss to the nation and that operators must have the necessary financial resources to cover such losses. This compensation is in addition to any penalties that may be imposed under other laws and regulations. Article 34 provides that, based on monitoring and supervision, the CNH may initiate a sanctioning administrative procedure to determine whether there was noncompliance with the technical provisions. Article 35 provides that violations of these provisions will be sanctioned in accordance with Articles 85–87 of the Hydrocarbons Law, 2014 or specific contracts.
According to Article 85 of the Hydrocarbons Law, 2014, the seriousness of the violation will be considered when determining a sanction. SENER sanctions noncompliance with the terms and conditions established in the assignments and contracts, with a fine of 15,000–75,000 times the minimum wage. Operators failing to comply with an exploration plan or production development plan will be penalized with a fine of 150,000–3 million times the minimum wage. In the case of oil and gas development and production activities that do not have a measurement system approved by the CNH, a fine of three–six million times the minimum wage may be levied. The application of sanctions and payments are regulated by the Federal Law of Administrative Procedure, 2018. Article 25 of the ASEA Law, 2014 also provides for penalties up to 3 million times the minimum wage depending on the severity of the violation of the environmental mandates.
No specific nonmonetary penalties for flaring or venting were found. However, Article 85 of the Hydrocarbons Law, 2014, states that within the scope of their oversight, SENER and the CNH should sanction serious or repeated violations of the Hydrocarbon Law with suspension or revocation of contracts or removal or disqualification of the personnel who provided their services to an operator, assignee, or contractor. Article 70 of the Federal Law of Administrative Procedure, 2018, states that administrative sanctions should be provided in the respective laws and may consist of the following
- additional fine for each day the violation persists
- detention for up to 36 hours
- temporary or permanent closure, partial or total closure of facilities
- others indicated by the laws or regulations.
Article 99 of the Regulation of Hydrocarbons Law, 2014, details the procedures and timelines the administrative authorities must follow when imposing fines. Sanctions should be applied without prejudice to the civil, criminal, or administrative liability that results from the application of sanctions by other legal systems and, where appropriate, from the revocation of the assignment, permit, or authorization, or the termination of the contract.
According to Article 25 of the ASEA Law, 2014, ASEA can suspend or revoke licenses, authorizations, permits, or registrations in case of repeat or serious violations or nonpayment of financial penalties. However, ASEA reportedly favors a “corrective enforcement” scheme under which operators can find a solution to achieve the required reduction.
Article 4 of the CNH Technical Provisions for the Use of Associated Natural Gas in the Exploration and Production of Hydrocarbons requires operators to conserve associated natural gas and sets technical standards. SEMARNAT and ASEA have technical and environmental standards regarding emissions from oil and gas operations. Articles 71–85 of the ASEA Guidelines for the Prevention and Comprehensive Control of Methane Emissions from the Hydrocarbons Sector cover emissions control measures, such as requirements regarding fugitive emission detection systems and equipment, including the following:
- quarterly comprehensive leak-detection-and-repair programs
- replacement or installation of zero-emitting venting equipment
- prioritization of capture technologies over flaring to reduce emissions from tanks and other equipment
- standards for monitoring and reporting.
Fiscal and Emission Reduction Incentives
No evidence regarding fiscal and other incentives for emission reductions could be found in the sources consulted. In fact, there is a disincentive to capture associated gas, because the value of associated gas calculated for royalty purposes is higher than the value of nonassociated gas until the contractual price of natural gas reaches a certain level. The formulas for calculating the value of associated and nonassociated gas can be found in Article 24 of the Hydrocarbon Income Law, 2014, which sets $5.5 per mmBtu as the natural gas price above which associated and nonassociated gas attain the same royalty rates.
Use of Market-Based Principles
Mexico is working on an Emissions Trading System (Sistema de Comercio de Emisiones) Test Program. In 2018, an amendment to the General Law on Climate Change (under SEMARNAT) established an emissions trading system that promotes emission reductions at the lowest possible cost. A three-year trial program began January 1, 2020. Operators of the installations associated with the development, production, transportation, and distribution of hydrocarbons can participate in the trading scheme. Only operators of those facilities with annual emissions of 100,000 tCO2 or more can participate in the trial program.
Negotiated Agreements between the Public and the Private Sector
No evidence regarding negotiated agreements between the public and the private sector could be found in the sources consulted.
Interplay with Midstream and Downstream Regulatory Framework
The Pemex Law, 2008, created a new legal framework for the national oil company. At the same time, responsibility for upstream regulation was shifted to the CNH, and the functions of SENER and the Energy Regulatory Commission were strengthened. In 2013, amendments to Articles 25, 27, and 28 of the Constitution, 1917, were adopted. They allowed for the participation of private firms in activities previously reserved for the state. In 2014, additional transitory articles were signed into law outlining the main aspects of the secondary legislation needed to implement the different sector legislative changes.
The 2014 secondary legislation created two bodies—the National Center for Control of Natural Gas (Centro Nacional de Control del Gas Natural) and National Energy Control Center (Centro Nacional de Control de Energía)—to operate, monitor, manage, and coordinate the gas and electricity networks. The National Center for Control of Natural Gas was tasked with managing the old Pemex gas pipeline network. Pemex withdrew from natural gas transportation, and private investors carried out a rapid expansion of the gas pipeline network. The pipeline transport capacity was tendered to interested shippers bidding through the open season process, and open access to the natural gas network was established. Interconnections with the US pipeline system were strengthened.