In accordance with the Constitution, oil and gas in place are owned by the people of Kazakhstan. Such ownership right is exercised through the state, as an institution. The state represented by the Ministry of Energy (MoE) grants to an investor a right to explore for, produce and dispose of the lifted oil and gas under an executed exploration and production (E&P) or just production (P) contract (concession-type).

The MoE is the competent authority for regulating all hydrocarbon related operations from upstream to downstream. The Minister of the MoE is the member of the government and represents the MoE in all state-level decisions with respect to hydrocarbon reserves explored and produced in Kazakhstan and refinery and sale of those and related petroleum products. The major objectives and competence of the MoE are listed in the Government Regulation (No 994 of 19 September 2014). The authorities of the MoE within each of the hydrocarbon activities are set out in specific laws as follows:

• upstream activities – in the Subsoil Use Code (No 125-VI of 27 December 2017); and
• midstream/downstream activities:
1. the Gas and Gas Supply Law (No 532-IV of 9 January 2012);
2. the Trunk Pipeline Law (No 20-V of 22 June 2012); and
3. the Petroleum Products Production and Sales Law (No 463-IV of 20 June 2011).

The details of such authorities are further developed in the numerous subordinate regulations, decrees and orders.

KazMunayGas JSC (KMG) is the national oil and gas company that is involved directly or indirectly in all upstream/midstream/downstream operations. QazaqGas JSC (“QazaqGas”) is the national gas transportation company.

Upstream

The Subsoil Use Code sets the rules with respect to:

• entering into E&P or P contract;
• key terms and provisions of such contracts;
• major requirements for the investors on conducting upstream activities onshore and offshore;
• material terms and conditions for setting up a joint venture with KMG; and
• joint development of a project or adjacent fields and other matters concerning hydrocarbons exploration, production and sales/utilisation.

The Subsoil Use Code is the only legal act that provides for a kind of the polling and unitisation rules that may be summarised as follows:

• the Subsoil Use Code does not define or separate “polling” and “unitisation”, but it permits several investors under different E&P or P contracts to enter into a JV-type of contract for the joint use of adjacent contract areas covered by their E&P or P contracts and certain facilities on those contract areas during development and production stages;
• such joint development of, and production in, different contract areas are permitted if they improve technical and economic numbers of at least one project under the relevant E&P or P contract; and
• such joint development of and production in different contract areas require changes to the applicable project documentation as well as approvals of the MoE and other relevant state authorities and expert organisations.

The upstream activities are also subject to various health, safety and environment (HSE) laws and regulations, some of which are mentioned in more detail further on in this Law and Practice chapter.

Midstream

The Trunk Pipeline Law regulates all matters regarding engineering, construction, use and liquidation of the oil or gas trunk pipeline. Trunk pipeline is a pipeline that stretches and is used outside of the contract area.

The major objective of the Gas and Gas Supply Law is to set out the rules on the ownership, transportation and sale of produced natural gas and related petroleum products, as well as on the industrial, commercial and residential use of those.

Several HSE laws and regulations apply to construction, use and liquidation of any trunk pipeline.

Downstream

The Petroleum Products Production and Sales Law regulates all matters regarding refinery and sales of various products from the refined crude oil.

Gas refinery matters are covered by the Gas and Gas Supply Law.

Relevant HSE requirements are stated in numerous HSE laws and regulations.

An investor obtains the right to explore for, develop and/or produce hydrocarbons under an E&P or P contract (concession-type) signed with the state represented by the MoE. Each of the E&P and P contracts is based on the model approved by the MoE. In practice, any deviation from the model contract is impossible.

In the 1990s, during the first years of Kazakhstan independence, the government used to sign the contracts of different nature (production-sharing contracts, risk service contracts, concessions, and licences) for exploration for and production of hydrocarbons. However, only two production-sharing contracts for two major offshore projects (the North Caspian (AKA Kashagan) project and Karachaganak gas condensate project) and one onshore multi-contract Tengiz project, each of which involves the participation of at least one multinational, like Chevron, Exxon, Total, etc, are still in effect and “grandfathered” from most of the current changes in law. Unlike the current E&P and P contracts, the 1990s major projects contracts are protected by confidentiality restrictions.

The general rule is that the right to be a party under an E&P or P contract is awarded under the results of a public auction. The auction is held by the MoE online. Although every bidder must confirm its financial (eg, sufficient cash amount on a bank account or a loan to finance minimal exploration works) and/or technical (eg, positive experience in offshore operations) capabilities in a submitted bid, the contract is awarded to a bidder depending on the highest amount of the signature bonus rather than on confirming the mentioned capabilities.

Certain E&P and P contracts may be granted to KMG directly through negotiations, without any auction. As a matter of practice, KMG shares the costs and benefits of the operations under such contracts with a strategic partner – usually, a foreign investor.

Such works, like drilling, seismic survey, workover and others require a separate licence from the MoE. Qualification requirements for the licence include ownership of required equipment, experienced personnel and holding of required technical documentation, all of which are listed in detail in the MoE Order No 77 of 28 October 2014.

Other activities that are regular in oil and gas business (ie, import of certain equipment, currency operations and use of explosives) are subject to various permit or notification requirements.

There is no tax stability in E&P or P contracts; only the contracts signed in the 1990s for major projects are carved out from this.

In general, the government changes the list of taxes occasionally. In 2024 the list of major taxes in upstream includes the following:

• Signature Bonus – a lump-sum amount paid for signing E&P or P contract.
• Mineral Extraction Tax (MET):
1. a volume-based royalty-type tax;
2. tax rate for oil – from 5% to 18% (depending on the volume of produced oil; the higher is the volume the higher is the rate) subject to 50% decrease if produced crude oil was supplied to domestic market;
3. rate for gas – 10% or, if the produced gas is supplied to domestic market, from 3% to 1.5% (the tax rate depends on the volume of produced gas and decreases upon increase of the volume sold to domestic market).
• Excess Profit Tax (EPT) – a tax on any portion of net income (if any) that exceeds 25% of deductions (all expenses made to carry out activities aimed at receiving income); tax rate – from 0% to 60%.
• Historical Cost Compensation (HCC) – a fixed payment (tax) to compensate the state of its costs of geological survey or field development undertaken prior to signing of E&P or P contract – for an offshore project or onshore project with unconventional hydrocarbons (eg, shale gas, coal-bed methane) or a complex geological or technical structure MET, EPT and HCC may be replaced by a single Alternative Subsurface Use Tax that is based on the world oil price and with the tax rate – from 0% to 42% for a complex onshore project and from 0% to 14% for an offshore project.
• Rent Tax on Export – a tax on export of crude oil or petroleum products; tax rate varies from 0% to 32% depending on the increase of the world oil price.
• Customs Export Duty (indirect tax) – a payment on any export of crude oil or petroleum products; the rate depends on world oil price.
• Financing the training of local employees – 1% of the production costs per calendar year.
• Financing R&D by/with local institutions – 1% of the production costs per calendar year.
• Financing social and economic development of the local community – 1% of the production costs per calendar year, and other taxes and mandatory payments.

A new Tax Code is expected in 2025 and certain changes may be made to the above list of taxes.

Information on profit sharing under the PSAs and other project contracts that were signed in the 1990s is confidential and not publicly available.

The regular income taxes are (i) corporate income tax of 20% on aggregate annual income, calculated as the difference between taxable income and deductible expenses and (ii) withholding tax of 5% to 20% on income paid to non-residents.

Also note 2.3 Typical Fiscal Terms: Upstream, specifically with respect to “Excess Profit Tax” and “Alternative Subsurface Use Tax” mentioned in that section.

KMG, as the national oil and gas company, has the following preferential rights under the law with respect to upstream contracts:

• to become an owner of the interest in any upstream contract (E&P or P contract, PSA and other contracts signed in the 1990s) to be alienated by an investor or the alienated direct or indirect controlling interest in such investor in case the state exercises its priority right under the law;
• to enter into an E&P or P contract through direct negotiations with the MoE;
• to be a trust manager of the interest in an E&P or P contract when such contract is terminated for any reason;
• to hold at least 50% interest in an E&P or P contract for offshore projects; and
• to hold at least 50% interest in an operator under an E&P or P contract with the mandatory participation of KMG (offshore projects).

The following requirements on local content in goods and services are applicable to upstream operations.

• There must be at least 50% of local content in all services procured within a calendar year.
• Every investor must comply with the MoE Procurement Rules (Order No 196 of 18 May 2018) that describe the procurement procedures in detail, except for an investor under an E&P or P contract for a project (offshore, gas or onshore with unconventional hydrocarbons or a complex geological or technical structure) – such investor should set its own procurement rules subject to certain conditions (such rules must provide for equal access to all potential suppliers and contractors, the investor must agree with the MoE and perform a programme for the development of local suppliers and contractors during production stage, etc).
• Procurement of goods and services must be done preferably through tenders and auctions.
• Every E&P or P contract must set out the minimal local content percentage in goods and services to be procured by investor.
• Investor must report to MoE annually on all goods and services procured within the preceding year and local content percentage in those.

The following requirements on local content in personnel applicable to upstream operations.

• Investor must give preference to local employees.
• To hire an expatriate employee, investor must obtain a relevant work permit or such expatriate employee must obtain a certificate on self-employment or residence permit.
• Every E&P or P contract must set out the minimal local content in every category (senior management, mid-level management, specialists and workers) of employees – the general rule is that there should be at least 70% of local employees within senior management and mid-level management, and at least 90% of local employees within specialists and workers.
• Investor must report to MoE annually on local content percentage in all hired employees.
• Investor must spend at least 1% of the annual production costs on training the local employees.

Once commercial production is confirmed by the state reserves commission at the MoE level, an investor may proceed to development and production subject to satisfying at least the following requirements:

• a field development project and other related technical project documents were approved by the experts and state authorities;
• gas utilisation programme was approved by the MoE and other state authorities; and
• all required environmental, construction and land-use permits were received.

All well-related works (eg, drilling and workover) must be done by a duly licensed contractor in accordance with the approved project documents (exploration project, test production project or field development project) and upon the investor’s approval of work plan and in accordance with the terms and conditions of the underlying E&P or P contract.

Every E&P or P contract must be based on and may not deviate from the relevant model contract approved by the MoE. Such model contract mirrors the imperative provisions of the Subsoil Use Code and includes the following key terms and conditions.

• Exploration period varies depending on the type of the project – regular or complex (offshore, gas or onshore with unconventional hydrocarbons or a complex geological or technical structure). In a regular project the initial exploration period in an E&P contract should be up to six years with the possible three-year extension for appraisal and further three-year extension for pilot production; such twelve-year period may be extended for an additional three years if an investor undertakes to drill one or more new wells and put a security deposit at the escrow account with a local bank – an investor must receive the MoE’s approval and sign an amendment to the E&P contract for every extension. In a complex project the exploration period may be up to 18 years, including nine years of initial exploration, six years of appraisal and three years of pilot production; to maintain such 18-year duration an investor must apply to the MoE for switching to the next type of works (from initial exploration to appraisal and then to pilot production) and sign a relevant amendment to the E&P contract.
• Production period is up to 25 years and at “large fields” (field reserves of more than 100 million tonnes of oil or 50 billion cubic metres of gas) – up to 45 years.
• For every period (exploration or production) there is a work program attached to the E&P or P contract that lists the works and investments to be made by investor every calendar year.
• Contract area is set in the attachment to the E&P or P contract and it is subject to extension or relinquishment upon agreement with the MoE.
• Every E&P or P contract requires delivery of all crude oil produced during exploration period, including pilot production, to the domestic market. Export of crude oil is permitted during the production period, but in practice it is limited due to the limited export capacities in Kazakhstan for its landlocked location. Export is controlled by the MoE through export quotas.
• There are clauses on penalties for non-performance of certain undertakings (eg, local contact requirements, supply to domestic market, and reporting).
• The provisions of an E&P or P contract are stabilised against changes in law, except for the changes on tax, customs, national security, environment, health and anti-trust matters.
• Investor may exit from the contract anytime by signing a termination agreement with the MoE. The MoE may terminate the contract:
1. if the investor did not rectify a breach(es) that MoE noticed to the investor;
2. if the investor:
1. is prohibited to perform certain activities under a court decision; or
2. performs activities under the contract without duly approved technical documentation;
3. there was a violation of the transfer restrictions under the law (see 2.9 Transfers of Interest: Upstream Licences and Assets); or
4. if the investor in a strategic field that is included into the government’s list of such fields (Government Regulation No 389 of 28 June 2018) refused to re-negotiate the executed contract for national security reasons of the government under the stated terms and conditions of the law in response to the MoE’s notice of the need in re-negotiation.

Any transfer of the interest in any upstream contract (E&P or P contract, PSA and other contracts signed in the 1990s) or any share (more than 1% of the total number of shares), including convertible instruments, in the holder of such interest or such holder’s controlling entity (unless an exemption under the Subsoil Use Code applies) through initial public offering (IPO) or direct sale is subject to the MoE permission. If the contract covers a strategic field (as mentioned in 2.8 Other Key Terms: Upstream), such transfer may also trigger the state priority right that is exercised through KMG. The decision on waiver or exercise of the state priority right is a part of the MoE permission.

A transferee must apply to the MoE for its permission. In the application the transferee must confirm its technical and financial capabilities. In case of IPO an issuer or a holder of the offered securities must apply to the MoE for its permission and disclose all key details of the offering in the application.

The MoE should decide on granting or rejecting its permission within one month and if the state priority right applies – within three months after receipt of the transferee’s application with the attached required documents in full. The MoE rejects granting permission if:

• there are national security concerns;
• there is a concentration of rights by a single investor or several investors from a single country under a single upstream contract;
• the transferee’s application does not satisfy the requirements of the law; or
• the state priority right was exercised or in other cases provided in the Subsoil Use Code.

Any transfer closed without the required MoE permission is considered null and void in Kazakhstan. In addition, the underlying upstream contract may be terminated by the MoE in case the required MoE permission was not received.

Kazakhstan is a member of OPEC+ group. Production and transportation of oil are controlled by the MoE through monthly export quotas and transportation schedules issued to every investor under an upstream contract.

Midstream and downstream facilities may be in private or state ownership. However, such midstream/downstream facilities as trunk pipelines, seaport terminals and refineries are considered “strategic objects”. Although they may be in private ownership, any transaction with those or with the shares (more than 5% of the total number of shares) in the owner of any of those or the owner’s controlling entities is subject to the prior government approval.

The government may exercise its state priority right to get at least 51% of the share in a new trunk pipeline to be constructed.

Private investments into midstream or downstream facilities are made through equity in the owners or operators of such facilities.

Transportation of oil/petroleum products through trunk pipelines and storage/transportation of commercial gas are natural monopolies. In general, tariffs for natural monopoly services are set based on cost-plus pricing strategy for at least five years.

Equal access to trunk pipelines and natural monopoly services is declared in the Natural Monopoly Law (No 204-VI of 27 December 2018) and Trunk Pipeline Law.

In case of limited access to oil/petroleum product trunk pipeline, the priority of access is given as follows:

• supplier of oil to domestic refineries for refining;
• owner of such trunk pipeline for transportation of its own oil/petroleum products;
• supplier of oil/petroleum products under the government’s instructions or international treaties;
• supplier – investor into construction or capacity increase of such trunk pipeline;
• supplier of the guaranteed annual minimal volume of oil/petroleum products for transportation under a contract with the owner of the trunk pipeline; and
• supplier of oil that may improve the quality of transported oil blend.

In case of limited access to a commercial gas pipeline/storage, the priority of access is given as follows:

• population that uses gas for personal needs;
• housing and utilities facilities;
• consumers using gas as a fuel or raw material in business;
• power station; and
• other consumers.

Only the use of trunk pipelines requires a licence from the MoE. Qualification requirements for such licence includes availability of the experienced personnel for the pipeline operation and security, measuring equipment and required HSE and technical documentation.

For other midstream/downstream activities it is necessary to obtain regular engineering, design and/or construction licences. Currently, the government is drafting a new Construction Code and a new licensing and permit regime for such activities might be introduced.

There is no restriction on the form and substance of the contracts in midstream/downstream operations and the relevant infrastructure owners/operators are free to use any type of contracts they find appropriate. Since Kazakhstan is a civil law jurisdiction, some contract clauses may be restricted by imperative provisions of the Civil Code (General Part of 27 December 1994 and Special Part No 409-I of 1 July 1999).

There are no specific taxes in midstream/downstream operations. A regular corporate income tax or withholding tax are applicable.

In case the government exercises its state priority right to get at least 51% of the share in a new trunk pipeline to be constructed, QazaqGas would act on behalf of the government.

QazaqGaz also has the right to exercise the state priority right to buy natural gas or commercial gas from an oil and/or gas producer.

Unlike in the upstream operation, in the midstream/downstream operations there are no special requirements on local content. However, mandatory local content in personnel applies through the general rules on receiving a work permit for expatriate employees. Local content in goods, works and services may be set through corporate procurement rules and different contracts with state authorities and national companies, oil & gas producers and others.

All export and domestic supply requirements are set through the upstream contracts (see 2.8 Other Key Terms: Upstream). Midstream/downstream owners/operators provide their services in accordance with the instructions of the oil and gas owners.

A private investor constructing infrastructure may receive the required land plot directly from the state, if such land plot is in the state ownership. In such case there would be insignificant acquisition fees. Or, if the land plot is in private ownership, it would be necessary to agree on the purchase with the private owner(s) and in such case the purchase value of the land plot would be negotiable. Usually, since the government is interested in constructing more new infrastructure facilities within the country, the government provides certain support to the private investors.

The MoE regulates the transportation of hydrocarbons by all transportation means (pipelines, tanks or rail) through monthly transportation schedules. Most of the interstate pipelines are controlled by the state and the operation of such pipelines are regulated by the interstate treaties rather than private agreements.

Private pipelines would be subject to the same open access rules as mentioned in the Trunk Pipeline Law and Natural Monopoly Law (see 3.2 Downstream Operations Run by a National Monopoly: Rights and Terms of Access).

Depending on the market situation, occasionally the government sets the limitations on the sale of certain products and/or pricing of those.

The MoE regulates the export of hydrocarbons by all transportation means (pipelines, tanks or rail) through monthly transportation schedules and export quotas. Depending on the market situation, occasionally the government sets export and/or import ban on oil or certain petroleum products.

In general, there is no restriction for transfers between private owners. But, note the mentioned (see 3.1 Forms of Private Investment: Midstream/Downstream) prior government approval with respect to the sale of interest in such facilities as trunk pipelines, seaport terminals and refineries – “strategic objects”.

In general, there is no restriction on any foreign investment in hydrocarbons, but note the mentioned right of the MoE to reject transfer of the interest in an upstream contract for concentration of several investors from a certain country in such contract (see 2.9 Transfers of Interest: Upstream Licences and Assets).

Foreign investors have the same investment protection guarantees as local investors. The key investment protection guarantees are granted in the local law (Subsoil Use Code, Civil Code, Entrepreneurship Code (No 375-V of 29 October 2015), etc) and various international treaties (Energy Charter Treaty, bilateral investment treaties, ICSID Convention, NY Convention and others) and may be summarised as follows:

• limited stability protection for an upstream contract against changes in law (see 2.8 Other Key Terms: Upstream);
• no discrimination and equal treatment of local and foreign investors;
• guaranteed compensation in case of expropriation – however, there are certain unfair provisions on the compensation value (eg, value to be determined by local appraiser who receives licence from the state, compensation in local currency, etc); and
• international arbitration in accordance with the UNCITRAL Rules is provided for E&P and P contracts for complex projects and there might be international arbitration in the 1990s upstream contracts; in other contracts disputes must be resolved in local courts only.

So far, the government has been supporting foreign investments into oil and gas exploration and production. However, the recent changes in law that undermined tax stability and introduced the state priority right and control over transfers between private investors, in addition to the persistent corruption among state institutions and the lack of the rule of law, have negatively affected on the investment attractiveness of Kazakhstan at the world market.

There are no sanctions applied to Kazakhstan.

The following principal laws on environmental matters apply to all hydrocarbon operations and the following state authorities control an investor’s compliance with each of those.

• The Subsoil Use Code sets the key HSE requirements that apply to upstream operations; the major regulator – the MoE.
• The Environmental Code (No 400-VI of 2 January 2021) is an umbrella legal act for setting all major environmental protection requirements (eg, environmental expertise, environmental impact assessment, public hearings, environmental permits, and use of best available techniques) for all business operations, including hydrocarbon operations, engineering, construction and others; the major regulator – the Ministry of Ecology and Natural Resources.
• The Water Code (No 481-II of 9 July 2003) regulates the use of water for business operation and other purposes; the major regulator – the Ministry of Water Resources and Irrigation.
• The Land Code (No 442-II of 20 June 2003) sets the rule for distribution of land plots, registration of title to any of those, transfer of those and other matters regarding land use; the major regulators – the Ministry of Agriculture and the local municipal authorities.

There are many other subordinate laws and regulations that apply to hydrocarbon operations.

Prior to commencing any material project activity (eg, exploration works, and construction of any operational facility) it is necessary to get a project design documentation, including environmental impact assessment, that is subject to various experts’ examination and state approvals. Approval of such documentation and any material changes to it also includes public hearing within the community that may be affected by the project activity. In general, the whole procedure of preparing the required documentation and getting it fully approved is a time-consuming procedure and requires involvement of several players (design institution, various experts, regulators, local municipal authorities, and others).

There is a separate section in the Subsoil Use Code on HSE requirements for offshore operations that are summarised as follows.

• Investor must use the best available environmental protection practice in its offshore operations.
• Investor should bear full liability for any environmental damage that resulted from offshore operations, unless such damage happened due to force majeure.
• Investor must arrange for transportation of controlling regulators to and from offshore facilities at its own expenses.
• Every offshore facility must be fully equipped and have the required personnel to prevent or liquidate any accidents/oil spill.
• Investor must have oil spill plans developed in accordance with MARPOL 73/78 and approved by relevant state authorities.
• It is prohibited to have oil tanks or storage facilities, including waste storage, offshore; and other requirements.

Decommissioning obligations during exploration period must be secured by parent company or bank guarantee; pledge of bank deposit in Kazakhstan bank or insurance coverage. During production period such obligations must be secured by the pledge of bank deposit in Kazakhstan bank. Bank deposit must be transferred with the transfer of the interest in the underlying upstream contract. Investor must provide the above required security for the whole period of operation (exploration and/or production) under the relevant upstream contract.

Decommissioning obligations in midstream/downstream operations must be secured by the guarantee of a bank or company whose shares are traded at the stock exchange, pledge of bank deposit in Kazakhstan bank, and pledge of assets or insurance coverage. Such security must be provided by investor in three years after commissioning of the relevant facility(ies) – as for the existing facilities that were built prior to the introduction of this rule in 2021 such duty to provide security came into effect on 1 July 2024. Although the investor may choose to use any of the above security forms jointly or individually at the beginning, upon the tenth anniversary after commissioning of the relevant facility(ies) or after 1 July 2024, as applicable, the pledge of bank deposit should cover 50% of the liquidation obligations and after the twentieth anniversary – 100% of such obligations.

The value of the security in upstream operation is determined in accordance with the project documentation that must include the market value of the required decommissioning works. In midstream/downstream operations such value is determined in accordance with the liquidation plan that the investor must prepare in accordance with the mandatory methodology (Order No 356 of 6 September 2021).

Decommissioning must be held with the participation of various state authorities. Investor cannot be released from its obligations under its upstream contract until the liquidation act is signed and approved by all parties.

Kazakhstan has been developing legislative framework in respect of climate change and reduction of greenhouse gas (GHG) emissions, and the summary of the main climate change laws is as follows.

• Kazakhstan ratified the UN Framework Convention on Climate Change on 4 May 1995 and the Kyoto Protocol to the UN Framework Convention on Climate Change on 26 March 2009.
• On 4 November 2016, Kazakhstan ratified the Paris Agreement dated 12 December 2015 (entered into force for Kazakhstan on 6 December 2016). According to the government’s Resolution (No 313 dated 19 April 2023), Kazakhstan approved nationally determined contributions (NDC) and intends to achieve by the end of 2030 a reduction of GHG emissions by 15% as its unconditional goal and 25% subject to certain conditions (eg, international investment, grants, technology transfer, and co-financing).
• Kazakhstan adopted the 2050 Development Strategy (the President’s Message dated 14 December 2012), the Concept on Transition of Kazakhstan to Green Economy (the President’s Decree No 577 dated 30 May 2013) and 2060 Carbon Neutrality Strategy (the President’s Decree No 121 dated 2 February 2023). These documents formed the basis for transferring of Kazakhstan to the green economy and set the long-term targets to achieve:
1. 50% of share of renewable and alternative energy sources (of total electricity generation) by 2050;
2. 80% rejection of coal-fired power generation or its mandatory accompaniment by CCS (carbon capture and storage) technologies by 2050; and
3. net-zero national GHG emissions by 2060.
• The Environmental Code provides for the goal to ensure by 31 December 2030 a reduction of the country’s carbon balance by at least 15% from the 1990 carbon balance level. The Ministry of Ecology and Natural Resources is the working body for implementation of international treaties in the field of climate change and regulates emissions and absorption of GHG to ensure achievement of NDC. The Environmental Code set the best available techniques (BAT) requirements, and from 1 January 2025 a comprehensive environmental permit (CEP) providing for the implementation of BAT is required for facilities with a significant negative impact on the environment (eg, production of oil and natural gas, production of petroleum products, processing of natural gas).
• Kazakhstan continues to develop renewable energy regulation to meet the target indicators of renewable and alternative energy sources in total electricity generation identified in the Concept on Transition of Kazakhstan to Green Economy:
1. 15% – by 2030;
2. 30% – by 2040; and
3. 50% – by 2050.

A summary of the main laws in renewable energy sector is provided in 6.1 Energy Transition Laws and Regulations.

Any limitation of any operation of a private investor may be done in accordance with the court decision, provided that such limitation (suspension or prohibition) is permitted by law.

In addition to the strategic documents described in 5.5 Climate Change Laws, the major laws that regulate transition to renewables are as follows.

• The Renewable Energy Law (No 165-IV dated 4 July 2009) is aimed to support development of renewable energy projects in Kazakhstan. Renewable energy projects can be implemented through:
1. renewable energy auctions which are conducted annually – an action winner can sell all its planned volume of energy to the state-owned single electricity purchaser (SEP) for 20 years;
2. intergovernmental agreements with the government (in respect of large projects); and
3. bilateral agreements.

In addition, based on recent legislative amendments, small-scale projects (up to 200kW) can be implemented to generate electricity for own needs and will be able to sell excess volume of electricity to the state based on standard power sale and purchase agreement signed with energy supply companies. SEP’s costs to support the use of renewable energy sources are allocated by SEP between wholesale energy market participants according to the specified procedure.

• The Electricity Law (No 588-II dated 9 July 2004) that sets out key terms for electricity generation, transmission and sale. On 1 July 2023, Kazakhstan introduced a SEP model and the balancing electricity market began to operate in real time. The SEP (Financial Settlement Centre for Support of Renewable Energy Sources LLP) conducts a centralised purchase of energy from energy producing companies (including renewables) and sells it to energy supplying, energy transmitting organisations, consumers and other market entities. SEP also acts as a balance provider for renewable energy companies which have a long-term PPA (power purchase agreement) with SEP.
• The Energy Supply and Energy Efficiency Law (No 541-IV of 13 January 2012) set the key energy efficiency requirements that must be satisfied in business operations and used materials and equipment.
• The Entrepreneurship Code and the Tax Code (No 120-VI of 25 December 2017) describe state support measures and investment preferences for implementation of renewable energy projects.
• The Land Code regulates procedures for reservation and obtainment of rights to land plots for construction and implementation of renewable energy projects.
• The Law On Architectural, Urban Planning and Construction Activities (No 242 dated 16 July 2001) provides for the procedures and requirements to construction and commissioning of the facilities.
• Several resolutions of the government and orders of the MoE provide for detailed procedures for sale and purchase of energy, conduction of and participation in auctions, calculation and indexation of auction prices, conclusion of power purchase agreements, etc.

The Environmental Code includes the principle of incremental application of BAT. The areas of application of BAT are determined in the Environmental Code and include all hydrocarbon operations. From 1 January 2025 the owners of oil and gas related assets will need to obtain a CEP and for this purpose they would be required to describe applicable techniques for prevention or reduction of negative anthropogenic impact on the environment.

Starting the beginning of 2024 the government has been approving BAT reports (recommendations) for all upstream/midstream/downstream operations. The BAT reports contains a description of the technologies, including CCUS and hydrogen.

As described in 6.2 Energy Transition and Oil and Gas Development, oil and gas companies will need to start applying BAT actively in their operations to reduce their impact on the environment. In addition, there is an increasing interest of oil and gas companies to invest in renewable energy operations for consumption of energy for their own needs or sale to SEP.

Currently, the government is preparing a framework for developing hydrogen industry and this may affect all gas related operations.

It is expected that by the end of 2024 there will an all-country referendum on construction of a nuclear plant. Construction and use of nuclear plant(s) may affect operation of the existing oil and gas facilities and regulation of oil and gas industry in a whole (eg, the government would be more involved in the uranium exploration and production and this would decrease its involvement in oil and gas industry).

Although the Subsoil Use Code defines the unconventional hydrocarbons, like shale gas, shale oil, heavy oil and coal-bed methane, and provides that such unconventional hydrocarbons should be explored and produced under an E&P or P contract for complex project, there is no well-developed legal framework or well-established practice on implementing such projects yet.

There are no special schemes relating to LNG projects in Kazakhstan.

The government and private investors have started collaborating with each other to implement digitalisation of all upstream/midstream/downstream operations for all projects in the country. While this would help investors to reduce their investment costs, it would also make the whole industry more transparent and help combating corruption that this industry is famous for in Kazakhstan.

Since during the last 30 years there were no material exploration of new hydrocarbon reservoirs and Kazakhstan has relied mostly on the reserves that were discovered during the Soviet times, recently the country has started facing the problems with the resource depletion, aging infrastructure and leaving foreign investors. During the last couple of years, the government has started actively developing various changes to the law to promote and support investments into oil and gas sector. The most significant changes include:

• the introduction of such concepts as “complex project” and “depleted fields” and related new tax and contract regimes for those under the Subsoil Use Code and Tax Code;
• more transparent regulation of downstream operations in the Trunk Pipeline Law and Gas Law;
• state support of geological survey under the Subsoil Use Code; and
• fine-tuning of the regulations on gas related operations in the Gas Law and Subsoil Use Code and others as mentioned in other sections of this guide. While the general objectives of those changes to support private investments and, hopefully, to decrease the state involvement gradually are plausible, the positive effect of implementation of those changes are still to be seen.