Vietnam: Power Sector Snapshot

Introduction

Vietnam’s power sector is expected to experience strong growth in 2026, driven by surging electricity demand, infrastructure expansion, and a major shift toward renewable energy. The Ministry of Industry and Trade (MOIT) projects electricity demand to grow by 10–12% under normal conditions, and up to 15% in an extreme scenario linked to high GDP growth and severe weather. This aligns with Vietnam’s economic outlook, which anticipates GDP growth of 6.5–8%, supported by trade recovery, public investment, and strong domestic consumption.

Vietnam’s revised Power Development Plan 8 sets aggressive targets for the power sector for 2030 and beyond. New legislation has been introduced to support renewable projects to enable market-based pricing and facilitate direct power purchase agreements (DPPAs) between generators and large consumers. Vietnam has revised targets for natural gas based power, with policies to incentivise both LNG and domestic gas-fired power projects. There is also renewed emphasis on the expansion of the transmission grid and sub-station and interconnection points, as well as private grids to facilitate renewable growth. However bankability of power purchase agreements remain a key concern due to lack of government guarantees, tariff uncertainty, curtailment risks and other factors which Vietnam is trying to address.

In this snapshot we take a look at the following key themes relevant to the power sector in Vietnam.

Revised Power Development Plan 8 (PDP8)

Following the launch of the Electricity Law on 30 November 2024 (which took effect on 1 February 2025) Decision No. 768/QD-TTg was issued on 15 April 2025 by the Prime Minister of Vietnam, which approved the revised National Power Development Plan VIII (PDP 8) for the period 2021–2030, with a vision to 2050. This decision replaces the previous Decision No. 500/QD-TTg, dated 15 May 2023.

Key highlights of the revised PDP8 are:

• 22,524 MW of LNG based power and 10,681 MW to 14,930 MW of domestic natural gas based power is targeted to be brought online by 2030;
• onshore and nearshore wind capacity is forecast to reach between 26,066 MW and 38,029 MW by 2030;
• offshore wind capacity is projected to be between 6,000 MW and 17,032 MW by 2035;
• solar power capacity targets (ground-mounted and rooftop solar) have been raised to between 46,459 MW and 73,416 MW;
• biomass power is set to contribute between 1,523 MW and 2,699 MW by 2030;
• waste-to-energy is targeted to contribute between 1,441 MW and 2,137 MW by 2030;
• battery energy storage system (BESS) capacity is targeted to be between 10,000 MW and 16,300 MW; and
• new introduction of nuclear power which is targeted to contribute 4,000 MW to 6,000 MW capacity.

Vietnam also expects to import 9,360 MW to 12,100 MW of electricity from Laos and China between 2021 and 2030, which is higher than the previous figures under the initial PDP8.

Higher targets are set for the period from 2031 to 2050.

Key policy rationale behind the above targets includes ensuring sustainable national energy security and to provide adequate, stable and high-quality energy supply while reducing emissions for economic and social development and ensuring national defense and security.

On 20 August 2025, Resolution 70-NQ/TW (Resolution 70) was issued by the Politburo of Vietnam. This is a strategic directive aimed at ensuring national energy security through to 2030, with a vision to 2045. It builds upon the earlier Resolution 55-NQ/TW, which came into effect in February 2020, and laid the foundation for PDP8. Resolution 70 marks a significant policy shift towards green, sustainable, and market-oriented energy development.¹

Existing renewable projects

By the end of 2024, the reported number of operational wind and solar power projects accounted for nearly 26% of the total capacity of the whole power system, including (i) 18.8 GW of ground-mounted and rooftop solar power projects and (ii) 4.1 GW of wind power projects.²

Following the expiration of the feed-in tariff (FiT) regime (e.g. the FIT1 regime), a number of solar and wind projects were ready to connect to the Vietnam Electricity (EVN) grid but did not have an approved mechanism to do so. These are referred to as the “transitional projects.” PDP8 classifies 173 solar and wind projects as transitional projects.

Decree 135/2024/NĐ-CP (Decree 135) came into effect on 22 October 2024 to provide regulatory support for transitional projects. While Decree 135 primarily governed rooftop solar projects in Vietnam, it also allowed these transitional projects to continue operating and entering into private offtake arrangements (on market terms instead of FiT prices) and enabling sale of surplus electricity (up to 20% of installed capacity) to EVN.

However, Decree 135 only applied to rooftop solar projects, which excluded a large number of transitional projects that were ground-mounted solar or wind projects. There was also a lack of clarity for transitional projects with partial grid connections. In addition, while Decree 135 allowed surplus electricity to be sold to EVN at market-based prices, there was no clear formula or mechanism for determining the price. In any event, the prices were significantly lower than previous FiTs, making projects financially unviable.

To overcome these challenges, Decree 58/2025/ND-CP (Decree 58) came into effect on 3 March 2025. Decree 58 replaces Decree 135 and outlines new regulations for the development of renewable energy and new energy sources, with a particular focus on offshore wind power projects.

Under Decree 58, transitional projects can now sell electricity under a market-based pricing framework, replacing FiTs. EVN is required to negotiate purchase agreements based on average market prices with transparent cost recovery mechanisms. Projects with battery storage or flexible dispatch capabilities may receive priority pricing or grid access, as may projects that are within zones identified in PDP8 as being “strategic zones”. Under Decree 58, EVN is required to coordinate with provinces to accelerate grid upgrades to reduce curtailment risks.

Transitional projects can participate in Direct Power Purchase Agreements (DPPAs) with large consumers. This provides an alternative revenue stream outside of EVN offtake, especially for industrial-scale wind and solar farms. In this regard, Decree 57/2025/ND-CP (Decree 57) came into effect on 3 March 2025, which sets out regulations on the mechanism for direct electricity purchase and sale between renewable energy power generation units and large electricity users in Vietnam. The scope of sources of renewable electricity that qualify for DPPAs under Decree 57 includes ocean energy, geothermal energy, hydropower, biomass, waste-to-energy and other renewable energy sources permitted under the new Electricity Law of 2024 in Vietnam. See Decree 57/2025 - Key Features and Impact on Direct Power Purchase Agreements in Vietnam for more details.

Natural gas-based power

Vietnam views natural gas as a transition fuel, with coal-based power gradually transitioning to gas-based power and then the future transition of gas-based power to hydrogen or carbon capture and storage (CCS).

The initial PDP8 released in 2023 had a targeted capacity of 22,400 MW of LNG-based power by 2030, which has been revised to 22,524 MW in the revised PDP8 indicating a continuing reliance on imported LNG.

In relation domestic gas-based power, the initial PDP8 released in 2023 had a targeted capacity of 24,930 MW of domestic gas-based power by 2030, which has been revised to a range of 10,861 MW to 14,930 MW in the revised PDP 8. The reason for a range rather than fixed target indicates uncertainty on the timing of new domestic gas supply becoming available.

To incentivise development of gas-fired power projects, Decree 56/2025/ND-CP (Decree 56) came into effect on 3 March 2025. Among other things, Decree 56 sets out the principles of passing through the fuel price (whether domestic gas or LNG) to the electricity price and the minimum long term contracted electricity output for gas-fired thermal power projects.

Decree 56 provides that for a gas-fired thermal power project using imported LNG, the minimum long-term contracted electricity output shall not be lower than 65% of the “average electricity output over many years of the gas-fired power plant project”. The “average electricity output over many years” would be stipulated in the power purchase agreement determined in accordance with (x) the regulations on methods for determining electricity generation service prices; (y) principles for calculating electricity prices to implement electricity projects; and (z) main contents of the power purchase agreement issued by the Ministry of Industry and Trade (MOIT).

The minimum long-term contracted electricity output for a gas-fired thermal power project using imported LNG would only apply for a period of 10 years from the commercial operation date of the project (which as per Decree 56 is required to be prior to 1 January 2031), and the project completion needs to be accepted by the competent state agency prior to such date. Where the financing of such project carries a tenor of longer than 10 years, then following the 10-year period the lenders and the project developer would need to renegotiate the minimum contracted capacity.

Projects using domestic natural gas do not have the minimum 65% long-term contracted electricity output requirement. This may have been due to Vietnam’s objective of maximising utilisation of domestically sourced natural gas for power generation (and optimisation of the extraction of natural gas from domestic reserves). A more predictable and stable supply of domestic natural gas (which is less expensive than LNG) may help lenders to the power project to take a view to not require minimum contracted offtake as power projects using domestic natural gas may be more likely to be dispatched. See Decree 100/2025 – Key features and impact on gas-fired thermal power projects in Vietnam for more details.

On 13 August 2025, MOIT chaired a meeting with investors of LNG thermal power projects and related parties. At the meeting, most investors reported difficulties and proposed several issues for discussion, focusing on:

• the application of a mechanism for two-part electricity pricing (capacity and energy);

• a mechanism for committed mobilisation volume (take-or-pay); and

• adjusting the minimum contracted mobilisation volume to a higher level than 65% and extending the application period (instead of applying within a term not exceeding 10 years).

These proposals are under review by the MOIT.

Battery Energy Storage Systems (BESS)

The original PDP8 released in 2023 had set out a target of 300 MW of BESS capacity by 2030. The revised PDP 8 now targets between 10,000 MW and 16,300 MW of BESS capacity by 2030.

This increase reflects Vietnam’s commitment to integrating more renewable energy sources into its grid. As noted above, under the revised PDP8, onshore and nearshore wind capacity is forecast to reach between 26,066 MW and 38,029 MW by 2030 while offshore wind capacity is projected to be 17,032 MW by 2035. Solar power capacity targets have been raised to between 46,459 MW and 73,416 MW. BESS capacity will support this growing share of solar and wind power in Vietnam’s energy mix, helping to stabilise the grid and manage peak demand. PDP8 requires concentrated solar power (CSP) projects developed under PDP8 to integrate a storage system of at least 10% of the project’s installed capacity with the storage time being 2 hours.

Vietnam began implementing BESS systems from 2019. However, due to the lack of a complete set of policies and regulations for BESS development, most BESS systems in Vietnam are after-the-meter systems and are generally small (<100 kW), installed in homes with rooftop solar panels. A few medium-scale systems have been installed after-the-meter or in small off-grid networks.

A tariff structure for BESS projects is being developed by MOIT, which would encourage BESS projects to use time-of-use pricing (to charge during low-demand, low-price periods and discharge during peak-demand, high-price periods). BESS projects could receive payments for available capacity, even if not dispatched. Projects that integrate BESS with solar or wind projects may receive preferential tariffs or grid access priority (as per Article 4 of Decree 58).

MOIT issued Decision No. 988/QD-BCT on 10 April 2025 on the pricing framework applicable to solar power projects. As per this Decision, in addition to a tariff for solar standalone power projects (without BESS), a separate tariff has been introduced for solar power projects that integrate BESS.

There is currently no dedicated power purchase agreement (PPA) model for standalone BESS projects. Clear guidance on the key terms of the offtake contracts that EVN would propose for such projects as well as tariff structures would be critical for development of BESS capacity in Vietnam. We expect this to be one of the critical steps to be undertaken by MOIT following the Prime Minister’s guidance under Decision No. 1009/QD-TT. See Development of Battery Energy Storage Systems in Vietnam for more details.

Nuclear power

Vietnam is cautiously restarting its nuclear power development efforts, which were previously suspended in 2016. The Ninh Thuận 1 and 2 nuclear power plants, originally planned with Russian and Japanese partners, were shelved in 2016 due to cost and safety concerns. Under Resolution No. 174/2024/QH15 of the Vietnam’s National Assembly and the revised PDP8, these projects are being reconsidered for development in the 2030–2035 period with a view to guaranteeing energy security, achieving economic growth target and meeting the commitment to reaching net-zero emissions by 2050.³

Nuclear development must align with the Law on Atomic Energy and Resolution 70, which prioritises energy security and green transition. The MOIT is tasked with ensuring centralised oversight, as nuclear projects fall under central government authority. On 10 January 2025, the Vietnam’s Prime Minister issued Decision No. 72/QĐ-TTg establishing the Steering Committee for the construction of nuclear power plants. The Steering Committee is tasked with directing the continued implementation of the investment policy for the Ninh Thuan Nuclear Power Project, overseeing review and progress, and proposing solutions to address issues arising during project development. The Prime Minister serves as the head of the Committee.⁴ EVN has been assigned as the investor of the Ninh Thuan 1 plant and Vietnam Oil & Gas Group (Petrovietnam) is assigned as the investor of Ninh Thuan 2 plant.⁵

Offshore wind

Under Decree 58, offshore wind projects are classified as those located beyond 6 nautical miles from the shoreline. Offshore wind projects can be procured selectively through the Independent Power Producer (IPP) model or the build-operate-transfer (BOT) model. Foreign investors can own up to 95% of offshore wind projects and are required to enter into joint ventures with (i) state-owned enterprises or (ii) enterprises in which more than 50% of their charter capital/total voting shares are held by a 100%-owned state-owned enterprise. Transfer of ownership by foreign investors are subject to regulatory approvals.

To incentivise development of offshore wind in Vietnam, Decree 58 exempts land/sea area use fee for up to 3 years during construction (with a 50% reduction of the sea area use fee for the next 12 years, and a subsequent land use fee exemption/reduction according the land laws). The minimum contracted output (Qc) is 80% per year for a period of 15 years. A more favourable Qc has been proposed to provide additional support and this is currently pending approval as discussed in more detail below.

Other incentives include import duty exemptions for equipment, government supported funding, and other incentives under the Investment Law in Vietnam, given renewable energy production is classified as an industry subject to a special incentive mechanism.

In recent years planned project development has been impacted by a delay in the issuance of survey rights, however, progress was seen in November 2025 with the Nam Bo offshore wind project in Vinh Long province being granted a sea area allocation decision for the purpose of conducting a survey.⁶  The FIMO Centre of the Vietnam National University has also recently agreed to provide Vingroup’s energy development company VinEnergo with NASA offshore wind measurement data for the research and survey of offshore wind energy projects.⁷

Going forward the Vietnam market will be required to address challenges with respect to ensuring sufficient port infrastructure for offshore wind projects by 2030 and wider supply chain issues.

Given the development trends and the implementation progress of power projects in Vietnam during the 2026–2030 period, the level of dependence on imported fuels (coal, LNG) and renewable energy sources is expected to increase, especially in the northern regions of Vietnam. Resolution No. 70 emphasizes ensuring national energy security, which requires accelerating offshore wind power development to meet economic, social, and security needs. Offshore wind power must be developed in alignment with national defense and maritime sovereignty protection, ensuring harmony between economic development and security.

The legal and regulatory framework for Vietnam’s offshore wind sector remains under development and market participants are engaged in active dialogue with the Government on a range of issues impacting development, including the issuance of survey rights, cost recovery mechanisms, technical and environmental standards.

On 22 October 2025, the MOIT issued Report No. 246/BC-BCT on the implementation of the revised PDP8 for the 2026-2030 period, proposing that the Politburo and the Prime Minister provide guidance and remove obstacles to accelerate offshore wind power development. The MOIT also recommended that the government issue legal policies and special mechanisms to support offshore wind power development, ensuring energy security and promoting renewable energy development during the 2026-2030 period and beyond. Recently, a Draft National Assembly Resolution to remove difficulties in national energy development during the 2026-2030 period has been submitted to the Standing Committee of the National Assembly, subject to approval. The Resolution, once issued, is expected to introduce mechanisms to further support offshore wind and the realisation of offshore wind targets under the revised PDP8.

Transmission and private grids

PDP8 also targets development of a synchronised transmission system to match the pace of power generation growth targets mentioned above, with a focus on 220 kV and 500 kV transmission lines to balance supply across regions (North–Central–South) and upgrades and expansion of substations and interconnection points to handle increased loads and renewable variability. Vietnam expects to focus on a build out of a smart grid capable of integrating large-scale renewables, managing demand-side response, enhancing system reliability and efficiency and apply advanced technologies for grid monitoring, automation, and digital control.

Since August 2024, the National Load Dispatch Centre has been separated from EVN to form the National Power System and Market Operation Limited Liability Company (NSMO). Separating the National Load Dispatch Center from EVN and establishing NSMO as an independent entity enhances transparency and reduces potential conflicts of interest in the electricity market. NSMO, being an independent operator, can manage the power system and market transactions more impartially, fostering a more competitive and efficient electricity market.⁸ The NSMO is regulated by MOIT and is expected to ensure that the power system and market operations are directly overseen by a regulatory body focused on industry standards and market regulations.

Decree 57, which sets out regulations in relation to DPPAs, enables DPPAs to be entered into under a “private DPPA” model, which is an off-grid model (although but there may be some grid connected elements as well on account of excess power being sold into the national grid). Decree 57 defines “private grid” to include overhead lines, underground cables, transformers, and associated equipment, which are the necessary infrastructure for connecting renewable energy generators to consumers.

Under Decree 57, those allowed to sell and purchase through private grid include: (i) renewable energy power generation units and (ii) large electricity consumers. While the former is defined as electricity entities that own renewable power plants producing electricity, the scope of “large electricity consumer” is subject to further guidance by the MOIT.

To develop a private grid, the following should be taken into account:

• Renewable generation facilities that exceed 1 MW in capacity must obtain an electricity operating licence, which is issued by MOIT. Approvals are also required from the local People’s Committee.

• Renewable generation facilities must conduct environmental impact assessments and obtain necessary environmental permits.

• Private grids must comply with national technical standards and regulations to ensure safety, reliability, and efficiency. For grid-connected models, the integration of private grids with the national grid must be in line with the approved national or provincial power master plan.

• Renewable energy projects may be required to provide financial guarantees or insurance to cover potential risks and liabilities. Renewable energy generators and consumers must report their transactions to the local People's Committee.

• Compliance with all regulatory requirements must be continuously monitored and maintained to ensure the ongoing validity of the project.

Project Procurement

BOT model

The BOT model is most commonly adopted for large-scale thermal and LNG power projects or for utility scale renewables that are identified as strategic projects by MOIT. Foreign and domestic investors build and operate the plant for a fixed term (typically 20–25 years), then transfer ownership to the government.

Under this procurement model, MOIT would issue request for proposals or expressions of interest and then evaluates bidders based on technical and financial capability etc. Selected developers would negotiate a long-term PPA with EVN.

Unlike the IPP projects discussed below, the tariff for PPAs in relation to BOT power projects follows a bespoke negotiation framework that is typically approved by the Prime Minister or relevant authorities on a case-by-case basis. These negotiations are often guided by precedent BOT contracts, especially for large-scale thermal or LNG-to-power projects.

Tariffs are typically structured to cover capital costs (including debt service and equity return), operation and maintenance (O&M) costs, fuel costs (if applicable) and foreign exchange risk and inflation adjustments. The tariff includes a fixed availability-based capacity charge and a variable charge based on actual generation. The internal rate of return (IRR) is usually capped (often around 12%, which is consistent with Circular 12 discussed below in the context of IPP projects).

IPP model

IPP projects are primarily selected and approved at the provincial level, with oversight and policy guidance from MOIT. The projects must be listed in or aligned with PDP8. The provinces are responsible for integrating power projects into their provincial master plans, including land-use and environmental zoning.

For most IPP projects (except offshore wind and nuclear), provincial governments handle investor selection, project approvals, land allocation and permitting. This decentralisation is intended to speed up implementation and attract private investment.

Circular 12/2025/TT-BCT (Circular 12) sets out the framework for determination of tariffs for IPP projects. Tariffs are calculated based on “reasonable and legitimate costs” over the economic life of the project. These include capital costs, O&M, fuel costs (if applicable), and other allowable expenses. The IRR is capped at 12%. The tariff is comprised of fixed price (which covers capital recovery and fixed O&M costs) and a variable price (which would include fuel costs and variable O&M for thermal power projects). Costs relating to interconnection may also be included if agreed between the developer and EVN. A temporary tariff may be agreed pending final negotiations to enable the developer to agree debt sizing with its financiers. The PPA tariff must be benchmarked against the “base year” of the electricity generation pricing framework (i.e. year for which the electricity generation pricing framework issued by MOIT is available for use to determine the tariff). If no framework exists for the base year, the most recent applicable year is used for comparison. Note that Circular 12 does not apply to BOT projects.

PPP Law

Vietnam’s first Public-Private Partnership (PPP) Law (PPP Law) came into effect on 1 January 2021. The PPP Law consolidates the law in relation to public projects and is intended to provide a clearer legal framework for PPPs and promote greater collaboration between the public and private sectors, including in the development and implementation of large-scale renewable energy projects (but excluding hydropower projects).

Unlike the BOT model and the IPP model above, competitive bidding is the preferred method for most PPP projects based on criteria such as technical capacity, financial strength, and alignment with PDP8 goals. However, direct appointment is allowed in special cases (e.g., strategic urgency, only one qualified investor) if it is justified and approved by relevant authorities.

Under the PPP Law, projects are classified according to the authority competent to issue the investment policy decision (IPD). Specifically, the IPD approval for PPP projects may fall under the authority of: (i) the National Assembly; (ii) the Prime Minister; (iii) the Ministers, heads of central agencies and other bodies of equivalent authority; (iv) the provincial People’s Council; or (v) the provincial People’s Committee.

PPP projects that are subject to the IPD approval of the National Assembly are those of “national importance” and of certain scale as below:

• using public investment capital worth VND30,000 billion or more (c.US$1,100 million);
• having substantial environmental impacts or posing potential risks in making serious environmental impacts (excluding nuclear power plants);
• using land subject to the requirement for conversion of uses from land of special-use forests of at least 50 hectares; of headwater protection forests or border protection forests of at least 50 hectares; arable land for growing rice covering an area of at least 500 hectares; or of production forests of at least 1,000 hectares;
• resettling at least 20,000 inhabitants in mountainous areas or at least 50,000 inhabitants in other regions; and
• requiring special legal frameworks or policies subject to the National Assembly's decisions.

These would include projects such as LNG storage projects, most of the LNG-to-power projects and large-scale hydro power plants projects.

PPP projects that are subject to the IPD approval of the Prime Minister include nuclear power plant projects.

The Ministers, Heads of central authorities and other equivalent competent agencies are authorised to approve the IPD for PPP projects under their management (other than the projects falling into the authority of the National Assembly and the Prime Minister).

The provincial People’s Council are authorised to approve the IPD for PPP projects under their jurisdiction and belonging to “Group A” projects under the Law on Public Investment (other than the projects falling into the authority of the National Assembly, the Prime Minister, the Ministers, Heads of central authorities and other equivalent competent agencies as mentioned above).

The provincial People’s Committee are authorised to approve the IPD for PPP projects under their jurisdiction and belonging to “Group B” and “Group C” projects under the Law on Public Investment (other than the projects falling into the authority of the authorities as mentioned above).

The classification of projects under Group A, Group B or Group C is in accordance with the Law on Public Investment and depends on investment thresholds and specific investment fields. In particular:

• Group A projects are, among others, (i) projects in the electricity industrial sector having an investment capital threshold of ≥ VND4,600 billion (c.US$180 million) or (ii) projects in the electricity engineering sector having an investment capital threshold of ≥ VND3,000 billion (c.US$120 million). These would include projects such as large-scale onshore wind farms, and 500 kV transmission lines.
• Group B projects are, among others, (i) projects in the electricity industrial sector having an investment capital threshold of VND240 billion to < VND4,600 billion (c.US$9.4-180 million) or (ii) projects in the electricity engineering sector having an investment capital threshold of VND160 billion to < VND3,000 billion (c.US$6.2-120 million). These would include projects such as medium-scale solar or wind farms, medium-scale onshore wind farms, BESS projects and 220 kV transmission projects.
• Group C projects are, among others, (i) projects in the electricity industrial sector having an investment capital threshold of < VND240 billion (c.US$9.4 million) or (ii) projects in the electricity engineering sector having an investment capital threshold of < VND160 billion (c.US$6.2 million). These would include projects such as rooftop solar clusters, small scale grid upgrades, small-scale biomass power projects, small-scale hydro power plants, and localized energy efficiency projects.

Several government support mechanisms are available under the PPP Law to encourage private investment in infrastructure projects, including those in the power sector. These include:

• Viability Gap Funding (VGF): The government may contribute up to 50% of total investment capital for projects that are financially unviable but socially or strategically important. This support is typically in the form of capital grants during construction.
• Tax incentives: PPP project companies may be eligible for corporate income tax reductions, import duty exemptions for equipment and materials and land use fee exemptions or reductions.
• Land allocation and site clearance: The government facilitates land acquisition and clearance. Investors may receive land use rights for the duration of the project.
• Revenue risk sharing: For large-scale or nationally important projects, the government may offer minimum revenue guarantees or compensation mechanisms if actual revenues fall below projections due to regulatory or market changes.
• Foreign exchange and currency risk mitigation: For foreign investors, the government may guarantee foreign exchange convertibility risk.
• Legal and regulatory support: PPP projects benefit from streamlined licensing procedures, priority in dispute resolution and access to government coordination units for inter-ministerial support.
• Access to government credit and guarantees: In special cases, the government may provide sovereign guarantees for loans or guarantees for EVN’s payment obligations under PPAs.
• Technical assistance and capacity building: Especially for complex sectors like energy, the government may offer feasibility study support, training and advisory services and access to public data and planning tools.

The PPP Law recognises several contract models, including BOT (Build-Operate Transfer), BOO (Build–Own–Operate), BTO (Build-Transfer-Operate), BTL (Build–Transfer–Lease), BLT (Build–Lease–Transfer), O&M (Operation & Maintenance) and other approved hybrid forms.

Bankability challenges with the EVN PPA

The bankability of PPAs in Vietnam has historically been a key concern for investors, particularly in the renewable energy sector. While Vietnam has made significant progress in expanding its power generation capacity, especially from solar and wind, several challenges have affected the financial viability and bankability of PPAs.

Circular 12 introduced a more flexible PPA template in relation to IPP projects, allowing parties to negotiate key terms such as performance commitments, dispatch and operation, billing and payment, force majeure and dispute resolution.

Some key bankability concerns are as follows:

• Lack of government guarantees: Traditional PPAs with EVN do not include sovereign guarantees for payment obligations. This has made it difficult for developers to secure international project finance, especially from commercial banks. Projects developed under the new PPP Law may be eligible for government support, however investors are concerned about unclear or unfavourable risk-sharing mechanisms, particularly around revenue guarantees, foreign exchange risks, force majeure and termination compensation. In addition, the PPP Law has cumbersome project preparation requirements. For example, the requirement to prepare a 1/2000 zoning plan is impractical for early-stage wind power projects, where turbine locations and transmission routes are not yet defined.
• Single buyer model: Vietnam has a day-ahead electricity market (DAEM) which is managed by the NSMO and supervised by MOIT. Generators, retailers, and large consumers (≥1 MW) are eligible participants. It is however currently a single buyer model with EVN being the sole purchaser. Investors are concerned about creditworthiness and payment delays, especially in the absence of third-party recourse. Vietnam’s Wholesale Electricity Market (VWEM) came into operation in 2019 with a view to transitioning from a single-buyer model (where EVN was the sole offtaker) to a multi-buyer, multi-seller model. However, currently the only buyers of power in the VWEM are EVN’s subsidiaries such as the Northern Power Corporation, the Central Power Corporation and the Southern Power Corporation. There is limited flexibility among this buyer group on negotiating prices or choosing suppliers independently. The legal framework for contract enforcement, dispute resolution and market monitoring is still evolving. As well, the information systems and data exchange platforms needed to support multiple buyers are still under development.
• Minimum Contract Quantity (Qc): For LNG-to-power projects utilising imported LNG, the minimum Qc is set at 65% of multi-year average generation applicable for gas fired projects during the loan repayment period, capped at 10 years from COD and available only to projects achieving COD before 1 January 2031. After this 10-year period, while the Qc level can be negotiated it is up to EVN whether or not to accept a Qc higher than 65%. Both the 65% threshold and the 10-year limit raise material concerns for international sponsors and financiers as the 65% Qc is considered inadequate and a 10-year commitment does not align with the usual tenors for offshore project loans. The COD deadline of 1 January 2031 further constrains the timeframe for projects to secure financing. For offshore wind project, the Qc level is at 70% during the loan repayment period, capped at 12 years (however this would not apply if the project fails to produce the minimum output as a result of the project’s fault or load demands or the electrical system’s failure to completely use electricity output due to technical limitations). The government has proposed to the Standing Committee of the National Assembly to issue a resolution to increase the Qc for imported LNG-to-power plants to at least 75% of the long-term average annual generation and extending the guarantee period to 15 years from COD.⁹ Although these proposals may improve lenders’ and sponsors’ confidence, it could potentially lead to higher electricity costs due to the higher LNG costs and are thus expected to be closely scrutinised by the Standing Committee of the National Assembly.
• Pass-through mechanism: While international lenders typically require full pass-through of all fuel-related costs, the calculation for gas fuel prices for LNG-to-power projects developed under the IPP model only include storage, regasification, transportation, and distribution expenses, and does not cover key items such as tolling, break fees and cancellation fees. Additionally, the government may reject pass-through of cost components not explicitly listed under Circular 12.
• Tariff uncertainty: In the case of transitional projects discussed above, the shift from FiTs to market-based pricing under Decree 58 has introduced pricing uncertainty. Transitional projects must now negotiate tariffs with EVN, often without a clear benchmark or floor price.
• Curtailment risk: Grid congestion, especially in southern provinces, leads to frequent curtailment of renewable energy. PPAs often do not compensate for curtailed energy, affecting revenue predictability.
• No deemed dispatch: The PPA may not contain deemed commissioning or deemed dispatch payments if the generator is unable to generate electricity for any other reasons outside of its control.
• No liquidated damages: The PPA may not cover liquidated damages for delay in completion. Whilst at first instance this appears beneficial to the generator under the project, this would enable EVN to claim general damages at law for a breach of the agreed implementation schedule. There would likely be no cap on liability under the PPA. This reduces the certainty and ability of the generator to quantify its potential liability.
• No termination payments: The generator would need to rely on its ability to claim general damages from EVN if the PPA terminates due to a breach by EVN. Whilst this would be subject to Vietnamese law, there is unlikely to be any compensation available to the generator if the PPA terminates due to force majeure.
• Change in law: The PPA does not have a specific provision to deal with the expenses or arising obligations due to changes in law. Vietnamese laws and regulations have changed from time to time to reflect changes to the government’s national strategies. Hence, the long-term investor of power projects may face a higher risk of a change in law.

Foreign ownership restrictions

Foreign investors can own up to 100% of the equity in renewable and thermal power projects, however in relation to offshore wind projects, foreign ownership is capped at 95%.

Restrictions on equity transfer

There is presently no restriction on equity transfers other than in the case of offshore wind projects. However, the mid to long-term foreign debt must be approved by the State Bank of Vietnam which will review the project’s approved Investment Registration Certificate (IRC). In granting a project permission to proceed under the project detailed lodged with the Department of Planning and Investment, the debt to equity ratio must be declared. Typically, a minimum debt of 20% is required. This debt to equity ratio is stated in the IRC.

Dispute resolution

Contracts law in Vietnam allows foreign law to be applied, however, there is no clear regulation on whether foreign law can govern PPAs developed under the BOT model. As well, there is no clear regulation on what dispute resolution mechanics/venues (e.g. international arbitration) can be agreed in relation to such contracts. This creates uncertainty for investors and lenders, especially foreign ones.

Under Circular 12/2025/TT-BCT, foreign law cannot govern the PPA for IPP projects in Vietnam. Circular 12 explicitly requires that the governing law of the PPA must be Vietnamese law.

In relation to power projects developed under the PPP Law, Article 55 of the PPP Law states: “The contract governing PPP projects and related documents must be signed between the Vietnamese state and investors, and PPP project enterprises must comply with Vietnamese law. Agreements on issues not regulated by Vietnamese law may be negotiated in the PPP contract as long as they do not contradict the fundamental principles of Vietnamese law.”¹⁰

Investors often request that the provisions in the contract should be governed by English law, not Vietnamese law. Choosing foreign law (e.g. English law) to govern/interpret the contract is a major concern for Vietnam. Vietnamese authorities are cautious because of risks and legal implications, especially in the energy sector.

Vietnamese law does not allow governing/interpretation of PPP contracts by foreign law, except for issues not regulated by Vietnamese law. This creates difficulties for foreign investors who want foreign law to apply to the entire contract. The PPP Law requires compliance with Vietnamese law, and foreign law can only apply to issues not covered by Vietnamese law. This is a major obstacle for foreign investors and lenders.

On 13 August 2025, MOIT proposed that LNG based power projects be allowed to apply foreign law to contracts and related documents. This proposal aims to attract foreign investors and lenders. MOIT also suggested allowing international arbitration for dispute resolution. These proposals are under consideration and may be included in future legal amendments. If approved, this will significantly improve the investment environment for LNG power projects in Vietnam.