Country
Assessment
According to Article 146 of the Law on Subsoil and Subsoil Use, 2017 , flaring is allowed during emergencies, well testing, trial operations of a field, and if it is unavoidable on technical grounds. Except in an emergency, flaring under all other circumstances requires a permit from the Ministry of Energy. Applications for a permit to flare raw gas can be submitted online. There are special considerations for the northern Caspian Sea region. For example, according to Article 274 of the Environmental Code, 2021 , flaring of liquids during well operations is prohibited and “flaring of hydrocarbons during well testing should be minimized using the best available technology, which is the safest for the environment.” The best available technology is identified during the process of the environmental impact assessment. Such flaring is allowed “only under favorable weather conditions conducive to the dispersion of the smoke plume, while the design of the flare units must ensure the complete combustion of hydrocarbons.”
Article 147 of the Law on Subsoil and Subsoil Use, 2017 , requires operators to minimize the volume of raw gas flaring and field development plans to include a section on raw gas processing or utilization. Field development plans are reviewed by the Central Commission for Exploration and Development “with the involvement of independent experts with special knowledge in the field of geology and development and not interested in the results of the examination,” as stipulated in Article 140. Articles 134–143 detail the necessary project documents and the review process. The Ministry of Energy’s Department of Subsoil Use organizes an independent review of project documents and development plans. According to Article 147, the gas-processing program is to be updated every three years. Annual reports on the implementation of the program must be submitted to the Ministry of Energy.
Article 147 of the Law on Subsoil and Subsoil Use, 2017 , prohibits the extraction of hydrocarbons without processing all raw gas. However, the law provides for several exceptions, all of which must be outlined in the field development plan. Article 146 provides exceptions under which flaring is permitted; Article 147 adds several others. The field development plan may include the operator’s own use of the gas or its sale to other parties. If these options cannot be justified economically, the field development plan may include re-injection for storage or enhanced oil recovery as long as other methods are ineffective in maintaining reservoir pressure and re-injection does not harm the environment. There are also regional considerations. For example, Article 274 of the Environmental Code, 2021 , prohibits the injection of associated gas for enhanced oil recovery in excess of the design parameters and volumes approved in the field development plan in the northern Caspian Sea region. These plans must be reviewed by an expert panel organized by the Department of Subsoil Use of the Ministry of Energy before being considered by the latter for approval.
Flaring during oil and gas operations must be measured and reported to the Ministry of Energy. Article 76 of the Law on Subsoil and Subsoil Use, 2017 , requires licensees to report on their activities covered under the permits issued by the Ministry of Energy. These reports may be periodic or one-time in nature. The Ministry of Energy develops standards for permissible raw gas flaring volumes, measurement, and calculation in accordance with Article 146. These standards should be observed in all reporting. Order 164, 2018, is the most recent ministerial order approving the methodology for calculating flare volumes. Article 203 of the Environmental Code, 2021 , details monitoring requirements for emissions, including from flares. Environmental permits, based on the environmental impact assessments, require the measurement of emissions to ensure compliance. They should also include a list of acceptable metering methodologies or, if metering is not feasible, allowed calculation methodologies. Article 186 states that monitoring at Category I facilities, which includes upstream oil and gas, “should include the use of an automated system for monitoring emissions into the environment.” Facilities operating before July 1, 2021, have until January 1, 2023, to install automated systems for monitoring emissions (Article 418). The data from automated emissions monitoring are considered primary data and are to be included in the new “National Bank of Data on the State of the Environment and Natural Resources of the Republic of Kazakhstan” (Articles 155 and 156). MEGNR will use these data to monitor compliance with environmental permits with or without a site visit (Article 174). The Environmental Code, 2021, introduces the concept of the integrated environmental permit, which is mandatory for Category I facilities (Article 111) starting January 1, 2025, for facilities commissioned on or after July 1, 2021 (Article 418). The permit is granted by MEGNR, in collaboration with other state entities if appropriate. Companies in Category I still need to conduct an environmental impact assessment. Article 113 defines the best available techniques, their purpose, and criteria for determining such techniques across sectors listed in Appendix 3. Techniques are intended to cover technologies as well as processes, practices, and approaches to designing, building, operating, maintaining, and decommissioning facilities. Article 113 establishes the Bureau of Best Available Technologies, falling within MEGNR, and outlines its tasks. The bureau will develop guidelines on the best techniques for all areas by July 1, 2023 (Article 418).
Both hydrocarbon and environmental regulators can impose penalties, the former for violating a flaring permit and the latter for violating an emissions permit. Penalties for violation of emission permits are more common. Article 175 of the Environmental Code, 2021 , authorizes MEGNR to assign daily monetary penalties. Interest is charged if payments are delayed or the offending party does not bring the operation into compliance within the specified time. According to Article 356 of the Code on Administrative Infractions, 2014, failure to perform the environmental requirements during subsoil use entails fines, the level of which depends on the size and income of the operator. In addition, environmental taxes are paid on all emissions, even when emissions are below the limits granted in permits. The penalties and taxes for stationary sources are paid to the local government at the location of the emission source, according to Article 577 of the Tax Code, 2017. Article 133 of the Law on Subsoil and Subsoil Use, 2017 , authorizes the Ministry of Energy to penalize violators of subsoil use contract terms unless operators bring the operation into compliance within the designated period (up to six months depending on the violation). Subsoil use contracts capture approved project documents such as field development plans that must have gas utilization scope and flares. Paying penalties does not negate the obligation to bring the operation into compliance. The operator has the right to ask for an extension of the specified period for compliance, which must be approved by the Ministry of Energy after an expert review. According to Article 356 of the Code on Administrative Infractions, 2014, flaring without a permit, except when allowed by law, or violation of permit conditions “shall entail a fine on subjects of small entrepreneurship in amount of 250, on subjects of medium entrepreneurship in the amount of 500, on subjects of large entrepreneurship in the amount of 2,000 monthly calculation indices.” Article 356 also lists penalties for hydrocarbon extraction without using and processing raw gas, violations of requirements in approved project documents, and environmental requirements. No evidence of penalties by the Ministry of Energy under these articles for violation of flare permits could be found.
Article 106 of the Law on Subsoil and Subsoil Use, 2017 , provides for early termination of the subsoil use contract under certain conditions, including violations of the contract terms. The operator can dispute the early termination decision in court within two months of receiving the notice. No case of contract termination based on a flare permit violation could be identified.
Article 202 of the Environmental Code, 2021 , details the standards for permissible emissions. It also clarifies that these standards apply to all flares other than those deemed technologically unavoidable by the regulator, the Ministry of Energy. According to Article 200, local executive bodies have the power to “establish stricter environmental standards” for air emissions if local conditions warrant it. According to Article 39, emissions standards for facilities with an integrated environmental permit will be established based on the best available techniques as determined by the Bureau of Best Available Technologies (see section 13 of this case study).
According to Article 127 of the Environmental Code, 2021 , emission taxes are calculated using base levies for various emissions, including those from flaring, provided in tax laws. For example, according to Article 576 of the Tax Code, 2017 , base tax rates for emissions from flaring are 20–278 times as large as the same emissions from other stationary sources. Paragraph 8 of Article 576 states that local authorities may increase the tax rates up to 200 percent of the base rate, except for emissions from flares, which can be increased to more than 200 percent of the base rate. Recent changes to the Tax Code align it with the Environmental Code, 2021. According to Article 575 of Law No. 402-VI, 2021, the base tax rates for emissions from stationary sources will be doubled from January 2025, and emissions from flaring will be assessed at the same rate as stationary sources. Article 130 of the Environmental Code, 2021, provides tax relief to facilities that obtain an integrated environmental permit through the adoption of the best available techniques (see section 13 of this case study). Penalties will be heavier for facilities that do not adopt the best available techniques.
Kazakhstan initiated the first ETS in Asia in 2013. Phase II covered 2014 and 2015. Phase III was delayed until the establishment, in 2018, of an online platform for monitoring, reporting, and verifying GHG emissions. The Environmental Code was periodically updated to include GHG quotas and related obligations and standards to assist with the evolution of the ETS market. Regulations on GHG emissions published in March 2022 provide further details. Only carbon dioxide emissions are included in the ETS market. Operators of oil and gas installations with annual GHG emissions of more than 20,000 tonnes of carbon dioxide equivalent (tCO2e) must obtain quotas. The penalty for noncompliance was waived in 2013 and 2014, and was about 5 monthly standard units or US$37.5/tCO2e in 2022. Operators of installations with emissions of 10,000–20,000 tCO2e a year must report emissions annually, although they are not required to participate in the ETS. The average 2022 price was about US$1.22 per tCO2e. Under the National Allocation Plan 2022–2025, the cap is 163.7 million tCO2e for 2023, 161.2 million tCO2e for 2024, and 158.8 million tCO2e for 2025.
The Law on Gas and Gas Supply, 2012 , supports the government’s policy of increasing gas use across the country to avoid wasting the country’s natural resources and replace coal and other fuels with higher emissions. The national gas system operator KazTransGas, wholly owned by KazMunayGas, is also trying to reduce fugitive emissions across its transmission and distribution network. Since 2018, KazTransGas has used remote methane sensing, which identified 3,963 leaks by the end of 2020. Fixing these leaks will reduce methane emissions and avoid the waste of gas. Article 15 of the Law on Gas and Gas Supply, 2012, establishes the preferential rights of the state to purchase raw or processed (“commercial”) gas assigned to the operator under the upstream contract. KazTransGas is responsible for procuring the gas from upstream operators. Article 15 stipulates that the raw gas price can include the cost of recovering raw gas, the cost of delivering it to a location where KazTransGas can take possession, and a profit margin of no more than 10 percent. The price of commercial gas can also include the cost of processing. The National Energy Report, 2019, of the Kazakhstan Association of Oil, Gas, and Energy Sector Organizations (Kazenergy) suggests that the price paid by KazTransGas has not been sufficient to cover “the costs associated with recovering associated sour wet gas that must be gathered, processed, and transported to an injection point.” However, the price has been sufficient to cover the cost of delivering “shallow dry gas” to KazTransGas. According to the KazMunayGas 2020 Annual Report , five operating companies, in which KazMunayGas is a partner, sell their gas to KazTransGas under Article 15 of the Law on Gas and Gas Supply, 2012, and five others, including the Tengiz, Karachaganak, and Kashagan operations, sell gas directly to domestic and export markets or use it for re-injection or meeting their own heat and electricity needs. The 2020 Annual Report of KazTransGas acknowledges the need to increase wholesale prices to ensure the commerciality of domestic gas sales. It refers to a ministerial meeting in August 2020 that called for an annual increase of 15 percent between 2021 and 2026. Although domestic gas sales are twice as large as export volumes, revenues from domestic sales accounted for only 6 percent of revenues in 2018, mainly because regulated prices of gas delivered to customers have been kept artificially low. Phased increases of transport tariffs and retail prices, possibly based on netback pricing, are part of the strategic objectives of KazTransGas. Reforming gas pricing and sending the right price signals across the natural gas value chain are expected to provide incentives to reduce flaring further by offering a commercially viable alternative to upstream operators and serving the government’s gasification policy efficiently