Vietnam’s power market is entering a new phase in which ambitious capacity targets must increasingly translate into system-compatible, executable and financeable projects.

The power sector has undergone rapid transformation over the past decade, driven by strong economic growth, rising electricity demand, and increasing policy focus on sustainability. Historically reliant on hydropower and coal-fired generation, Vietnam is now shifting toward a more diversified energy mix with a significant emphasis on renewable energy, with independent power projects (IPPs) remaining an important development model. This transition has been accelerated by government incentives, particularly feed-in tariffs (FITs) for solar and wind projects, which triggered a surge in installations between 2018 and 2021. As a result, Vietnam has emerged as one of Southeast Asia’s leading markets for solar power.

Vietnam’s power sector is moving from policy-led capacity expansion to system-integrated execution. For investors, lenders and developers, the next investment cycle will be shaped not only by the scale of new capacity required, but by whether projects are aligned with planning, grid capability, dispatch requirements, bankable offtake arrangements and executable development pathways.

The legal architecture supporting this transition has developed rapidly. The Electricity Law No. 61/2024/QH15, as amended (the “Electricity Law”), took effect on 1 February 2025 (updating). Its implementing framework includes Decree No. 56/2025/ND-CP (“Decree 56”), including the amendments under Decree No. 100/2025/ND-CP; Decree No. 57/2025/ND-CP (the “DPPA Decree”); and Decree No. 58/2025/ND-CP (the “Renewable Energy Decree”). The latter two decrees were amended by Decree No. 243/2026/ND-CP (“Decree 243”).

The Law on Investment No. 143/2025/QH15 (the “Investment Law”) and Law on Planning No. 112/2025/QH15 (the “Planning Law”) took effect on 1 March 2026, alongside Resolution No. 253/2025/QH15 (“Resolution 253”) on specific mechanisms and policies for national energy development for 2026–2030. The revised Power Development Plan VIII (the “Revised PDP VIII”) was approved under Decision No. 768/QD-TTg dated 15 April 2025, while the National Energy Master Plan was revised under Decision No. 363/QD-BCT dated 28 February 2026 (the “Revised NEMP”). These reforms sit alongside Vietnam’s new foreign investment strategy. Implementation and commercial risk allocation remain decisive.

Three points follow. First, market entry is increasingly planning- and procedure-driven, making early preparation essential. Second, bankability is project- and structure-specific: offshore wind, liquefied natural gas (LNG) power generation, utility-scale renewables, rooftop solar, direct power purchase agreements (DPPAs), new energy and storage each operate under materially different regulatory and revenue frameworks. Third, grid integration is now a financing variable. Vietnam’s power market is demonstrably investable, but bankability continues to depend materially on project-specific risk allocation, grid integration and the applicable offtake framework.

Macro Context: Evolution of Vietnam’s Power Sector

Vietnam’s power sector is entering a structurally different phase of development. The sector’s evolution is no longer driven principally by the need to add generation capacity at pace, but increasingly by the need to reconcile sustained demand growth with energy security, system reliability, decarbonisation objectives and the physical constraints of an increasingly complex power system.

First, demand growth continues to be underpinned by Vietnam’s broader economic transformation. Industrialisation, manufacturing expansion, urbanisation and rising electricity consumption are expected to remain key drivers of power demand. The growth of energy-intensive manufacturing, the expansion of data centres and other digital infrastructure, and the gradual electrification of transport and industrial processes are likely to increase both the volume and the profile of electricity demand. Total system output in the first quarter of 2026 reached approximately 76.86 billion kWh, up 6.6% compared to the same period in 2025. The government has also called for an increase in power generation of over 15% in 2026 to support a targeted gross domestic product (GDP) growth rate exceeding 10%. Accordingly, the central policy question is shifting from simply securing sufficient generation capacity to ensuring that capacity is available at the right location, at the right time and with sufficient flexibility to maintain system reliability. [1][2]

Second, the generation mix is undergoing a fundamental transition. Vietnam’s traditional reliance on hydropower and coal-fired generation is increasingly being supplemented, and in certain respects displaced, by renewable energy, LNG-fired generation and potentially new fuel technologies. According to the Revised PDP VIII in 2025, the total installed capacity of the power system is projected to reach approximately 183,291–236,363 MW by 2030 and under this updated framework, renewable energy (excluding hydropower) is targeted to account for approximately 28–36% of electricity generation. This transition reflects not only resource considerations and energy-security objectives, but also Vietnam’s broader decarbonisation commitments. At the same time, the increasing penetration of variable renewable energy creates a different set of system requirements, including balancing capacity, grid reinforcement, storage and more sophisticated dispatch arrangements. LNG and other flexible generation technologies therefore assume a role that extends beyond their contribution to installed capacity: they may serve as complementary resources within an increasingly renewable-based system.

Third, the regulatory model is evolving from a FIT-led expansionary regime towards a more controlled, system-based approach to deployment. The earlier feed-in-tariff model demonstrated the ability of relatively simple price incentives to mobilise substantial private investment in renewable generation. However, the unprecedented pace of development also exposed structural weaknesses, including transmission congestion, curtailment of renewable generation, geographical concentration of projects, and a mismatch between generation capacity and grid readiness. In response, the Revised PDP VIII and the Revised NEMP adopt a fundamentally different approach, under which renewable energy development is no longer driven solely by investor demand or tariff incentives but is coordinated with system planning, transmission capacity, energy storage deployment, and the operational flexibility of the national power system.

Taken together, these developments indicate a transition from a capacity-addition paradigm to a system-integration paradigm. The next phase of Vietnam’s power-sector development will consequently depend less on the ability to attract generation investment in isolation and more on the ability of the regulatory and market framework to coordinate generation, networks, fuels, flexibility and demand. For investors and developers, this represents a material change in the regulatory landscape: bankability will increasingly depend not only on project economics and tariff arrangements, but also on the project’s fit within the evolving architecture of Vietnam’s power system.

 

Regulatory and Legal Framework

The current framework is increasingly focused on coordinating investment, planning, grid integration, market operation and project implementation across the power sector.

Core laws

No single statute governs a power project in Vietnam. Depending on the technology, location and project structure, development and operation may engage the Electricity Law, investment and bidding legislation, land and planning rules, environmental requirements, construction law, marine-area legislation, competition rules and other sector-specific instruments. The applicable route must therefore be assessed project by project rather than by reference to a single ‘primary’ law.

The Electricity Law is the core sector statute. It governs, among other matters, electricity development planning, investment in electricity works, renewable and new-energy power, electricity operation licences, competitive electricity markets, electricity trading, system operation and dispatch, electricity safety and sectoral State management. It also provides the statutory basis for direct power trading and for the continued evolution of Vietnam’s competitive electricity market.

The Investment Law governs investment policy approval, investor selection interfaces, foreign-investment market access, project registration and investment incentives. It must, however, be read together with the Electricity Law and the applicable bidding, land, planning, environmental, construction and other specialised regimes. In practice, a project’s executability depends on the alignment of these regimes, particularly planning status, land or sea tenure, investor-selection route, grid connection and the sequencing of approvals.

The Bidding Law 2023, as amended (the “Bidding Law”), has become increasingly important as Vietnam moves from FIT-led deployment toward competitive investor selection for relevant power projects. The applicable selection method, evaluation criteria and commercial consequences depend on the project category and the specific statutory route; price is important in certain tenders, but should not be described as the universal criterion for all power-sector investor selection.

Decree No. 274/2026/ND-CP (the “Investor Selection Decree”), effective from 21 August 2026, provides the current general implementing framework for selecting investors for business investment projects. Power-sector bidding must be assessed against that decree and its transitional provisions, together with the Electricity Law, Decree 56 and any applicable special mechanism.

Planning architecture

The planning framework is now an operational part of project development rather than a high-level policy overlay. The Planning Law must be read with the Electricity Law, the Revised PDP VIII, the Revised NEMP and the special mechanisms under Resolution 253. Planning consistency can directly affect investment approval, project sequencing, grid connection and the ability to proceed to construction and operation.

Resolution 253 is particularly significant for the 2026-2030 period. Its Article 4 establishes an ‘updating adjustment’ mechanism for power development planning, distinct from a full planning revision, and permits specified updates including the addition of battery energy storage projects to improve system operability. An updating adjustment does not require a strategic environmental assessment. These mechanisms are time-limited and should be considered together with the detailed implementing rules applicable to the relevant project.

The Revised NEMP complements the Revised PDP VIII by framing energy development across fuels, infrastructure and system requirements. For investors and lenders, planning alignment is therefore not merely a licensing issue: it increasingly informs grid accessibility, implementation timing, dispatch exposure and the durability of a project’s revenue case.

Emerging Regulatory Layer

Vietnam’s regulatory framework is also becoming more market-oriented. Article 47 of the Electricity Law recognises direct power trading, while the DPPA Decree, as amended by Decree 243, regulates two statutory routes: direct trading through a private connection grid and direct trading through the national grid. Their eligibility, contractual architecture, pricing and settlement arrangements are materially different and should be analysed separately.

Under the private-connection-grid route, renewable generators may sell directly to eligible large electricity consumers and, following Decree 243, specified electricity retailers within qualifying zones or clusters. The parties may negotiate the electricity sale price, and Decree 243 removed the former express linkage to the applicable generation-price ceiling. It also introduced additional rules for in-zone retailers and clarified rooftop-solar requirements, including an exemption from development registration for rooftop solar installed specifically for a qualifying private-grid DPPA.

The national-grid DPPA is structurally different. Eligible renewable generators of wind, solar or biomass with capacity of at least 10 MW participate directly in the competitive wholesale electricity market and sell generated electricity into the spot market. The large consumer (or other eligible participant) continues to purchase physical electricity from the relevant power corporation, power company or eligible retailer and enters into a forward contract with the renewable generator. Commercial settlement therefore combines regulated/market electricity transactions with the separately agreed forward-contract terms; it should not be described simply as a bilateral electricity price agreed between generator and consumer.

Circular No. 29/2026/TT-BCT (the “Wholesale Market Circular”), effective from 20 July 2026 (subject to provisions effective from issuance), governs operation of the competitive wholesale electricity market and also addresses large electricity consumers participating in direct power trading. The national-grid DPPA must therefore be read together with the Wholesale Market Circular, rather than under the DPPA Decree alone.

Decree 243 also materially revised the regime for surplus electricity from self-produced and self-consumed rooftop solar. It increased the generally permitted sale of surplus electricity from 20% to 50% of output calculated under the prescribed methodology, with a transitional ability through 31 December 2030 for the parties to agree a higher percentage where the relevant grid can safely absorb it. Different rules apply to certain mountainous; border and island areas not supplied from the national grid. Electricity discharged from storage charged by the rooftop-solar system is included in surplus electricity for these purposes. Where surplus is sold to a Vietnam Electricity Group (EVN) power corporation or power company, the price is linked to the preceding year’s average market energy price, subject to the applicable ceiling; where qualifying surplus is sold to an in-zone retailer, price and volume may be negotiated. Licensing requirements continue to apply unless an exemption is available.

Another defining characteristic of this emerging regulatory layer is the growing influence of climate policy and sustainable finance. Vietnam’s commitment to achieving net-zero emissions by 2050 is driving the gradual establishment of a domestic carbon market while environmental, social and governance (ESG) standards are becoming increasingly relevant to project financing, corporate governance and investment decision-making. As international lenders and institutional investors place greater emphasis on environmental performance and governance standards, compliance with ESG principles is evolving from a voluntary consideration into an important commercial requirement. Consequently, renewable energy regulation is no longer confined to electricity law alone but increasingly operates at the intersection of energy policy, climate commitments, financial regulation and international sustainability standards, reinforcing the transition toward a more integrated and market-oriented renewable energy sector.

Project Development Lifecycle in Practice

Developing Renewable Energy Projects in Vietnam: Key Sequencing Considerations and Practical Bottlenecks

Renewable-energy project development in Vietnam is sequential, but the sequence is not identical for every project. The required approvals depend on matters including project type, investor-selection route, planning status, land or sea use, environmental classification, construction scope, grid connection and electricity licensing. The practical focus should therefore be on critical-path sequencing rather than a generic checklist.

Step 1: Site Selection and Transmission Capacity Considerations

At this stage, the investor identifies a suitable project site based on solar or wind or other resources, land availability and proximity to transmission infrastructure. A preliminary assessment of grid capacity is typically conducted to evaluate whether the proposed generation output can be accommodated by the local network. Here, Vietnam faces critical bottlenecks. Transmission has not kept pace with generation, leading to congestion and curtailment. Delays commonly arise where available transmission capacity is insufficient or where planned grid reinforcement projects have not yet been implemented. In such cases, developers may face curtailment risks, project redesign requirements or uncertainty regarding the timing of grid connection.

Step 2: Investment Approval and Project Company Establishment

Depending on the project, development may require investment policy approval and investor approval or investor selection, followed by project registration and establishment or use of an appropriate project company. An Investment Registration Certificate is not required in every case, and the precise sequence should be mapped against the Investment Law, the Electricity Law and any applicable special investor-selection mechanism.

Although this process appears relatively straightforward under the applicable legislation, practical implementation often presents a more complex picture. Delays frequently arise during the investment approval stage, particularly where there is insufficient alignment between national power planning instruments and local planning frameworks, including provincial land-use plans and sector-specific development plans. While statutory timelines for the appraisal and approval process are clearly prescribed under Vietnamese law, actual processing periods may be significantly extended due to inter-agency consultations, planning inconsistencies and policy considerations at both central and local levels. Consequently, the timing of project company establishment and subsequent development activities is often dependent on the provincial authority’s interpretation of law and planning-related issues that fall outside the developer’s direct control.

Step 3: Permitting Requirements and Land-Related Challenges

The permitting package is project-specific and may include environmental approvals, land or sea-area procedures, construction-related approvals or exemptions, fire-prevention and firefighting requirements, grid-connection and technical agreements, a power purchase agreement (PPA) or DPPA documentation, electricity operation licensing and other sectoral consents. These instruments should not be presented as a uniform list applying identically to every power project.

In practice, land-related matters can be a major source of delay. Processes relating to land recovery, compensation, resettlement, site clearance and land-use conversion, particularly where agricultural or forestry land is involved, can materially affect project schedules. While the current legal framework provides mechanisms for facilitating these procedures, implementation frequently relies heavily on local circumstances, stakeholder engagement and negotiations with affected land users.

In addition, investors must also engage with the competent electricity authorities and network operators to secure grid connection arrangements and satisfy applicable technical requirements. The review and approval process may involve extensive technical assessments and coordination among multiple parties, which can result in timelines that differ substantially from those contemplated under the relevant regulations.

Step 4: Commercial Operation and Subsequent Operations

Achieving commercial operation represents a critical milestone for any energy project, as it marks the commencement of revenue-generating activities. Nevertheless, the period immediately preceding and following the Commercial Operation Date (“COD”) often presents its own set of operational challenges.

Commissioning and performance testing require the generating facility to demonstrate stable and reliable operation under prescribed technical conditions. In regions experiencing transmission constraints or network congestion, the ability to complete testing procedures and satisfy COD requirements may be affected by external grid conditions.

Moreover, operational challenges do not necessarily cease upon the achievement of COD. Renewable energy facilities may subsequently be subject to dispatch limitations or output restrictions arising from transmission bottlenecks, system balancing requirements or localized oversupply conditions. These factors can affect actual energy production and should therefore be carefully considered during project planning and financial modelling.

Investor Selection & Market Entry

Article 23 of the Investment Law identifies three general forms of investor selection: auction of land-use rights, bidding to select an investor, and investor approval in the cases specified by that Law. For power projects, this framework must be read together with the Electricity Law, the Bidding Law, land legislation, Resolution 253, Resolution No. 254/2025/QH15 (“Resolution 254”) and any project-specific special mechanism. The applicable route is determined by the nature of the project, land status and the relevant statutory regime; it is not an elective three-route menu for investors.

Competitive bidding

Competitive bidding applies where required by the Electricity Law, the Bidding Law, the Investor Selection Decree and the implementing rules for the relevant project category. Under Decree 56, specified thermal and renewable power projects may be subject to investor-selection bidding where the statutory conditions are met. The bidding dossier and evaluation methodology must be reviewed for the particular technology: the proposed electricity price is an evaluation criterion where an applicable generation-price framework exists, while other criteria may apply where it does not. The commercial effect of bidding can be significant because key PPA parameters may be established through the tender process rather than left entirely for post-award negotiation.

For qualifying power-sector investment projects scheduled to operate during the period specified in Article 8 of Resolution 253, the winning bid electricity price is the PPA price and may not exceed the price framework applicable in the bidding year. The power purchaser must negotiate and execute the PPA with the successful bidder, with a 30-day period for negotiation and execution running from submission of a valid PPA negotiation dossier for projects within that special regime. Thermal power, small modular nuclear and offshore wind projects are excluded from Article 8’s winning-bid-price rule and require separate analysis.

Auction of land use rights

Auction of land-use rights may apply where the conditions under the Land Law 2024 are satisfied, including the relevant requirements concerning the State-managed land fund, planning and completion of the land-recovery/compensation process. Whether a power project falls within this route is therefore fundamentally a land-status question and must be tested against the specific site and project structure.

Approval of the investor

Investor approval without auction or bidding is available only in the cases permitted by the Investment Law and applicable special legislation. Resolution 253 adds energy-sector mechanisms for specified projects, including certain offshore wind and urgent electricity projects, but the legal basis and competent authority differ by project category and period. These special routes should not be generalised into a broad right to direct appointment.

Resolution 254 separately provides additional land-related mechanisms, including specified cases in which land may be allocated or leased without auction of land-use rights and without investor-selection bidding. Its application should be assessed independently from investor approval under the Investment Law; a land-allocation exception does not by itself answer every investment-approval or sectoral selection question.

For offshore wind, ownership conditions and financial capacity requirements must be assessed separately. Article 28 of the Renewable Energy Decree requires qualifying foreign participation to include at least 5% domestic participation by specified State-owned or State-controlled enterprises in the project company’s charter capital or voting shares, together with the applicable security concurrence and other conditions. Decree No. 272/2026/ND-CP (the “Offshore Wind Decree”), effective from 4 July 2026 to 31 December 2030, separately requires applicants for the specified investment-policy and investor approvals to demonstrate project equity of at least 20% of total investment capital and a lending commitment for the balance. Under Article 8, the minimum investment contribution is 15% for a foreign investor or foreign-invested economic organisation and 5% for a qualifying domestic enterprise without foreign members or shareholders. These contribution requirements are distinct from the project company’s ownership requirements.

The practical message is readiness rather than ‘first mover’ status. Investors should establish the applicable planning and investor-selection route early, maintain evidence of financial capacity and committed financing in bid-ready form, and treat land/sea rights, grid interface and PPA terms as parallel workstreams. Offshore wind requires an additional national-security and domestic-participation analysis from the outset.

To be continued…, from ambition to execution. The next instalment examines project finance, offtake and curtailment risk, investment incentives and the wider energy transition.

[1] https://vietnamenergy.vn/evns-production-and-business-performance-in-q1-and-key-tasks-for-q22026-35898.html?utm

[2] https://www.eav.gov.vn/d/en-US/news-o/EVN-urged-to-boost-power-generation-by-over-15-per-cent-in-2026-60-111-58980?utm

Download a copy of the Part 1 here.