Vietnam’s electricity sector remains state-led, but it is no longer a purely state-owned system. The legal framework now supports a mixed market in which the Vietnamese state and its enterprises retain control over the electricity grid and retail backbone, while private and foreign capital plays a major role in developing generation capacity. As of mid-2026, the cornerstone statute is the 2024 Electricity Law, which took effect in early 2025 and sits alongside the investment, enterprise, land, construction, environmental and competition regimes. In practice, no electricity generation project can be analysed under the Electricity Law alone.

The market is partly unbundled. Investment in generation is relatively open and includes state-owned generators, independent power producers, build–operate–transfer (BOT) projects and renewable developers. Whilst it is possible under Vietnamese law for the private sector to develop and own transmission infrastructure, ownership and operation of transmission remains concentrated in the state-owned electricity utility Vietnam Electricity (EVN) and its group entities, and distribution is still largely organised through EVN’s regional utilities. Retail supply is therefore far less liberalised than generation, and the single-buyer structure continues to shape project bankability, dispatch and payments. That basic structure explains why Vietnam can appear open to the private sector and foreign investors on paper but still be highly centralised in commercial reality.

Electricity storage now deserves to be treated as a distinct segment rather than a mere add-on to generation. For several years, battery energy storage systems were discussed mainly as pilot or behind-the-meter assets, but policy has moved and storage is now part of mainstream planning under the revised National Power Development Plan VIII (“Revised PDP8”). Even so, the regulatory model for storage is still maturing, especially where standalone systems need a reliable revenue stack, grid service payments or a clear tariff pathway.

EVN is the central corporate actor in the sector. It sits at the heart of transmission, much of distribution, system purchasing and the retail relationship with most consumers. EVN remains the single largest electricity generator in its own right, mainly developing, owning and operating large-scale thermal and hydro power generating assets. Its corporate group includes the National Power Transmission Corporation, known as EVNNPT, the main regional power corporations and generation-related entities. Even where EVN does not own an asset, it is often the key offtaker, counterparty or operational gatekeeper.

Outside EVN, the most important state-linked generation players are PetroVietnam and PV Power in gas and thermal projects, together with Vinacomin or TKV in coal-related assets. Those SOE groups remain important because Vietnam’s baseload and fuel-linked generation still depend on state-led hydrocarbon ownership and development and mining policy. These SOEs are less active in renewable energy generation, and it is the private sector including foreign investors that has led the development of renewable energy in Vietnam through solar including rooftop, onshore wind and industrial energy solutions. Foreign sponsors and investors are active in new-generation LNG-to-power, offshore wind development studies and acquisitions of operating or late-stage projects.

A notable structural development has been the separation of the national grid system and market operation function from EVN into the National Power System and Market Operator (NSMO). That separation does not turn Vietnam into a fully independent liberalised market, but it is important because it separates the grid system operation and dispatch functions from state utility electricity purchase.

Foreign investment is generally permitted in Vietnam’s power sector, especially in generation and associated infrastructure. There is no broad prohibition on foreign ownership of electricity generation projects, and foreign sponsors have long participated through project companies, joint ventures, share acquisitions and BOT structures. In practice, however, being legally allowed to invest is only the beginning. The real constraints lie in project approvals, planning permissions, land use right or sea-area access, licensing, competition review, grid availability and the terms on which a generation project can sell electricity.

The approval process depends on the project type, scale and location. A foreign investor will usually need to confirm that the project is included in the relevant power planning documents (such as the Revised PDP8 and regional development plans) or implementation lists, then obtain the necessary investment approvals, enterprise registrations, relevant land and marine access rights, environmental approvals, construction approvals and sector operating licences. For strategic or politically sensitive assets, the practical review can also include national security and infrastructure sensitivity considerations, especially where the asset touches coastal or border areas, critical grid infrastructure or large data flows. Offshore wind and other marine projects raise these sensitivities more apparently than solar power or onshore wind projects.

Vietnam does offer customary investor protections under its investment framework, including protection against unlawful expropriation, access to the Vietnamese courts and, depending on treaty coverage and contract structure, the possibility of international arbitration. Whilst these protections are broadly afforded under Vietnamese laws, local laws can always be changed, and a more important question is whether such protections can be afforded under enforceable contracts or investment treaties. For projects involving large investment amounts, foreign investors pay particular attention to whether those protections are reinforced through project agreements, government support arrangements or international treaties. Outright expropriation has to date been less of an issue in Vietnam. More important for project feasibility is whether the project developers can rely on a stable enough tariff income stream, payment and foreign exchange availability to finance the project on acceptable terms.

Commercial, tax and other investment incentives are available, but they should not be overstated. Investors may access tax, land and import-related incentives if the project qualifies under the broader investment regime, and strategic energy projects continue to receive policy support. That said, the issues international investors talk about most often are not tax incentives. They are EVN creditworthiness and payment reliability, curtailment or non-dispatch, reliable and continued payments during relevant risk events, termination compensation, foreign exchange convertibility, allocation of project risk and change in law risk, fair and transparent dispute resolution, and contract enforcement against SOEs in Vietnam.

Sales of power industry assets or businesses and mergers involving power companies are governed less by a single sector-specific transfer code and more by a layered set of general laws. The main regulations are Vietnam’s investment and enterprise laws, competition regime, land laws and regulations regime governing land use, the electricity licensing framework and the contract package for the project itself. A share sale in a project company will usually be simpler than an asset sale, but both transactions require careful planning because a project’s key rights are often embedded in licences, approvals, land arrangements, and electricity sale and concession agreements rather than in the physical asset alone.

In practice, buyers may focus on a short list of threshold questions. They want to know whether the project remains validly included in the applicable power development plan, whether the project company still satisfies licensing conditions and is legally compliant, whether land use rights or lease rights are stable, whether the power purchase agreement (PPA) can remain in place after the transaction, and whether any change-of-control consent is required from EVN, the Ministry of Industry and Trade (MOIT) and the ministry responsible for the sector, provincial authorities other counterparties. In short, all of this means the Government of Vietnam.

Competition clearance can be relevant for larger deals, although Vietnam does not impose a power-sector-specific concentration cap of the sort seen in some other countries. Instead, transactions are tested under Vietnam’s general merger control regime. That means the review is driven by turnover, asset, transaction value or market share criteria rather than a standalone energy ownership ceiling. Even where formal competition risk is low, a buyer may still face intense regulatory scrutiny if the asset is strategically important or if the transaction affects a project with a significant public profile.

A prospective electricity generation investor is not subject to a single statutory fitness test for all electricity asset acquisitions, but capability still matters. Regulators and counterparties commonly look at whether the incoming investor has financial capacity, development, operational and technical experience and capability, and a credible plan to complete or operate the project. Under Vietnam’s PPP Law (Law No. 64/2020/QH14), investors in BOT power projects must satisfy specific eligibility criteria covering financial standing, equity contribution capacity and relevant technical track record. That point is especially important for projects that remain under development, because the state is increasingly focused on whether awarded capacity will actually reach commercial operation rather than remain tied up in what might in reality be a speculative venture designed to leverage a development right.

Vietnam has a centralised planning model for the electricity. The MOIT remains the principal policy and regulatory authority, but major planning and investment decisions still involve the Prime Minister and, depending on the issue, provincial people’s committees and other ministries. The national electricity sector planning basis is the Revised PDP8, together with its implementing regulations. In practice, these instruments do more than provide state policy direction; they decide which technologies, regions and project plans are politically acceptable.

The NSMO is central to dispatch, balancing and market operations, while EVN and EVNNPT are the main bodies responsible for procurement, grid rollout and practical system management. Vietnam’s planning and operating model is still therefore highly state-planned. Developers therefore need to follow both the formal plan and the informal implementation signals that come from the MOIT and other state authorities.

Provincial authorities also matter more than overseas investors sometimes expect. Even when national policy is supportive, a power generation project can stall if local land clearance, environmental approvals, access approvals or administrative co-ordination are weak. Often this is because of the experience and the ability to implement, or lack thereof, of state authorities. The relationship between central planning and provincial execution is therefore one of the defining features of power sector development in Vietnam, and explains why the same national policy can produce very different project outcomes across provinces.

The past year and the first half of 2026 have seen quite a bit of legislative change for Vietnam’s power sector, although how this plays out in terms of bringing much-needed new investment remains to be seen. The 2024 Electricity Law came into force in 2025 and was followed by many implementing decrees that now frame project development, licensing, direct power sales, and renewable or new energy policy. Taken together, they represent a real effort to modernise the sector’s legal architecture while preserving the state’s planning and system-control role. There is a plan to amend the Electricity Law as well.

Several changes stand out. Decree No 56 reshaped the rules on power project development planning, project development and investor selection. Decree No 57 replaced the earlier direct electricity selling rules and strengthened the framework for direct power purchase arrangements between renewable generators and large consumers. Decree No 58 dealt with renewable and new energy development, while Decree No 61 refreshed the licensing regime. Alongside those decrees, the MOIT also updated tariff and power purchase documentation for certain project categories and continued refining market and technical rules.

PDP8 was updated in 2025. It increased 2030 capacity targets across a range of generating types, raised the target capacities of solar, wind, imported power and storage, and reintroduced nuclear generation into the medium-term policy picture. For industry sponsors, lenders and large-scale electricity buyers, the most important message is that Vietnam is trying to ramp up electricity generating capacity faster than the previous iteration of PDP8. But the challenge for Vietnam remains – whilst the politicians and regulators have been busy over the last one to two years, private sector developers are less impressed, with the rate of investment in large-scale greenfield generating capacity, including in renewables, being considerably less active. The gap between generating capacity rollout and the state’s objectives continues to widen. Despite all the legislative activity, the activity has not been where it really needs to be, and that is in the capacity of central and provincial authorities to actually implement large-scale generation projects, it is in grid readiness, it is in tariff reform and it is in commercial risk allocation. In these areas, there is still a lot of work to be done.

In mid-2026, policy discussion is now focused less on whether Vietnam will continue expanding its power sector and more on how that expansion will be delivered. High-level energy security policy remains firmly in favour of rapid capacity additions, stronger grid infrastructure, and more diversified fuel and technology choices. Offshore wind, LNG, storage, cross-border power and eventually nuclear or small modular reactor policy all sit within that broader push. The state is not retreating from the need for there to be investment. But the state needs to make that investment suitably attractive again in order for its planning needs to be met.

The policy direction is clearer than it was several years ago. The revised National Power Development Plan VIII approved under Decision No 768/QD-TTg dated 15 April 2025 (“Revised PDP8”), Politburo Resolution No 70-NQ/TW dated 20 August 2025 on ensuring national energy security to 2030, with a vision to 2045, and National Assembly Resolution No 253/2025/QH15 dated 11 December 2025 on mechanisms and policies for national energy development for 2026–2030 point towards a larger, more diverse and more market-based electricity system, with stronger support for renewables, LNG, domestic gas, battery storage, direct power purchase agreements and transmission investment.

Direct power purchase agreements (DPPAs) are one of the most important developments for corporate electricity users. Decree No 243 and Circular No 29, both of which were issued in June 2026, make DPPAs more practical. They clarify that the mechanism covers renewable energy generators, large electricity consumers and retail electricity units in industrial-zone and similar models. Decree No 243 also expanded eligible large consumers beyond production customers to include users such as data centres, electric vehicle charging stations and battery swapping facilities, subject to the relevant connection and eligibility requirements.

For greenfield developers, though, the policy initiatives are all well and good, but they need to translate into actual investment outcomes. This means asking whether the tariffs offered can support the necessary return on investments, based on the financial and other efforts needed to get projects into commercial operation, as well as whether those initiatives will achieve bankable risk allocations, better project contracts, more helpful support from state bodies, etc. Experienced developers have learned from earlier renewable rounds and the failure of Vietnam’s IPP regime to support new large-scale private sector investment that ambitious policy language on its own is not enough.

Digitalisation and system data are also moving up the agenda. That matters because the next phase of the sector will require more sophisticated dispatch, demand forecasting, grid management, metering and settlement systems, especially if direct electricity selling, increased renewable energy flows and storage integration all expand at the same time. Vietnam’s challenge is therefore not only to build more megawatts; it is to manage a more complex power system than the legal framework was originally designed to support.

Vietnam’s power sector is interesting because it is at a cross-roads. Vietnam was previously successful in attracting large-scale foreign and private sector investment in thermal power through its BOT power scheme and successful feed-in tariff (FIT) schemes for renewables. But Vietnam did away with much of that, and arguably went too far the other way by developing the dispatch market mechanisms without providing assurance of revenue streams to support large-scale investment cost recovery. The state wants and plans for private sector investment and participation, but right now it is not going the extra distance to attract private sector investment in greenfield development by accepting that private capital needs some degree of investment return certainty and fair risk allocations. In many jurisdictions, a market is either heavily centralised or substantially liberalised. Vietnam sits in between. The private sector, including foreign investors, can build electricity generation projects and bring in international financing, but they do so within a framework where planning approval, grid access, dispatch and offtake remain strongly influenced by state institutions and where those state institutions are falling short in their commitments in return for the investment.

Another distinctive feature is the speed of policy evolution. Vietnam moved from generous FIT support for solar and wind to a far more controlled and contested environment in a relatively short period. That transition created significant legal and commercial issues, including tariff uncertainty, project backlog, curtailment and disputes over whether projects qualified for legacy FIT pricing. Many private sector developers saw EVN as reneging on its contractual commitments and the Vietnam state as being complicit in that. Those issues still influence lender and investor sentiment, including with the sector moving into a new regulatory phase.

A third feature is the growing overlap between traditional utility regulation and new-economy demand. Data centres, advanced manufacturing, green supply chains and corporate decarbonisation are now shaping energy policy as much as classic industrial demand. That is one reason the DPPA framework matters so much. It is not only an energy law reform; it is also part of Vietnam’s strategy to attract export-oriented, electricity-intensive investment without relying solely on the old single-SOE utility and monopoly buyer model. The challenge, though, remains for the largest electricity projects requiring significant capital investment, where direct electricity selling may not yet be feasible (eg, because of location or grid constraints) and with EVN remaining the only electricity offtaker, but with the PPA terms with EVN being now worse than they were under previous models.

The Vietnam Wholesale Electricity Market (VWEM) is a regulated order-of-pricing dispatch market rather than a fully liberalised electricity selling market. Generators do not simply sell into an open bilateral platform with free pricing; instead, dispatch, contracting and settlement operate through a controlled framework in which market participation, contract structure and administered pricing elements all remain important. The result is a hybrid model that mixes competitive dispatch with heavy regulatory supervision and lack of alternative buyers.

In commercial terms, many plants still rely on standardised power purchase structures that resemble contracts for difference. A generator may receive payments linked partly to market outcomes and partly to regulated or agreed components under its power sale arrangements. That means the market price is relevant, but it is not the sole determinant of project revenue. For lenders, one of the main bankability issues is therefore not only whether the market exists; it is how much merchant exposure the electricity generating project is really carrying after all contractual and regulatory adjustments. The short answer is that most generators are forced to participate in the VWEM without a bankable availability-based tariff structure to underpin economically feasible investment return.

Vietnam does not yet operate a mature capacity market in the way some developed power systems do. Certain plants may receive fixed or quasi-fixed payment elements under their contractual arrangements, but these do not amount to a broad, transparent standalone capacity market. Ancillary service and flexibility needs are becoming more important as renewable penetration rises, yet the monetisation framework for those services still needs development. That gap is one reason storage policy is receiving so much attention. More importantly, that gap is also why the private sector has not been able to commit to large-scale greenfield thermal or renewables power project development since the BOT and FIT regimes ended with replacement regimes that simply fall short.

Large consumers such as data centres are also beginning to influence the discussion. Whilst investment in data centres in Vietnam still lags compared with its neighbours, the importance of data centres in reshaping the electricity sector is the same in Vietnam as it is in most countries. These users care about reliability, grid sufficiency, clean power sourcing and price visibility. The DPPA framework is therefore especially relevant to them, whether through grid-connected structures or direct transmission arrangements. Even so, large consumers should not assume they can contract around the regulated system entirely. In most cases, they still remain exposed to the realities of grid charges, system constraints and the broader regulatory environment.

Vietnam permits electricity imports and has increasingly relied on them as part of its broader energy security strategy. Imports from neighbouring systems, especially those of Laos and China, already play a practical role in balancing domestic needs and supporting regional supply. These flows are typically organised through cross-border arrangements that depend on specific interconnection infrastructure, governmental approvals and negotiated commercial terms rather than a simple open trading model. In that respect, cross-border power remains strategic infrastructure, not just ordinary trade.

The Revised PDP8 raises the profile of imports further by increasing planned imported electricity volumes towards 2030. At the same time, it introduces a more outward-looking ambition for renewable and new-energy exports in the 2030 to 2035 horizon, including potential exports to countries such as Singapore and Malaysia. Those export ambitions are politically important, but they are still at a much earlier stage than the import arrangements. The legal and technical pathways for export projects are more complex because it requires not only generation development but also cross-border transmission, market design and diplomatic co-ordination.

Approvals for imports and exports are project-specific and heavily regulated. The key issues are intergovernmental co-ordination, planning inclusion, interconnection approval, pricing methodology, and consistency with domestic system security. Investors should expect cross-border projects to involve a greater public-law overlay than a domestic plant selling under a conventional EVN-linked structure. In practice, that often means longer development timeframes and greater exposure to policy sequencing. One attractive feature, though, of imported electricity PPAs to date in Vietnam is that the PPAs negotiated have been considerably more bankable than what EVN is prepared to agree for domestic projects, with availability-based tariff structures, USD payments offshore and more sensible overall risk allocations.

Vietnam’s current electricity mix still rests on a conventional backbone of hydropower, coal and gas, even though renewable capacity has expanded rapidly. Hydropower remains structurally important, especially because it contributes both energy and system flexibility. Coal continues to matter for baseload supply, despite decarbonisation pressure. Gas, including the LNG pipeline under development, is expected to play a larger balancing and transition role over time, though actual project delivery remains the critical variable.

Solar and wind have transformed the installed-capacity picture more quickly than the dispatched-energy picture. Vietnam’s earlier FIT rounds created a large build-out, particularly in solar, but grid constraints and curtailment have limited the practical value of some assets. That experience is one reason current policy is placing greater emphasis on transmission, storage and more controlled project sequencing. Capacity growth without evacuation capacity is no longer viewed as a sufficient success metric.

Looking ahead, the Revised PDP8 points to a much more diversified 2030 system. Solar targets have increased sharply, onshore and nearshore wind remain significant, offshore wind has a clearer strategic place, LNG stays important, imported power grows, and battery storage moves from pilot status into mainstream planning. Perhaps the most politically striking change is the return of nuclear power to the medium-term planning conversation. Whether all of that capacity will be delivered on schedule is uncertain, but the direction of travel is clear.

Vietnam does not impose an electricity-sector market share cap of the kind seen in some other unbundled markets. There is no single rule that says one generator or group cannot control more than a stated percentage of supply nationwide. The more important legal framework is the general competition regime, which applies across sectors and can capture anti-competitive agreements, abuse of dominance and notifiable economic concentrations. In the power sector, however, concentration is influenced as much by policy design as by competition law. The ability of the private sector to engage in these kinds of anti-competitive behaviour in Vietnam is severely limited, because electricity sale and purchase agreements are invariably based on EVN’s own forms for large-scale generators. Direct selling of electricity is also limited. Even premises consuming rooftop solar or inside-the-fence generated electricity can always buy from the grid and EVN. If anything, the economic concentration lies with the state-owned electricity generators including EVN itself and the fact that it is the sole grid operator.

That is to say, it is EVN’s continuing role in transmission, distribution, retail supply and the single-buyer model which already creates a concentrated structure by design. Vietnam’s power sector regulations therefore require competition through the VWEM, the dispatch market and the administered system but do not allow or effectively provide for competition in transmission or offtake. There is effectively no buyer-choice at the retail level.

For investors, the practical takeaway is straightforward. Market concentration is not usually the first obstacle to investment in the electricity generation sector in Vietnam, unless the transaction is especially large or strategically sensitive. The more immediate issues are planning status, licensing, change-of-control consent, project completion risk and whether the acquired asset has a durable revenue profile. Competition review still matters, but it rarely displaces the sector-specific investment issues. The real competition issues are those mentioned in the previous paragraph.

Vietnam’s competition authorities have jurisdiction over anti-competitive conduct in the power sector, and the National Competition Commission is the key institution under the general competition regime. In theory, that covers collusive arrangements, abuse of market power and anti-competitive concentrations. In practice, however, many of the most sensitive issues in electricity are not classic cartel or manipulation cases. They are questions of regulated access, dispatch priority, tariff design and institutional power within a partly monopolistic system.

Sector regulators also play an important role. The MOIT, the Electricity Authority of Vietnam and the NSMO all influence how the market operates, how participants are monitored and how compliance issues are addressed. Their involvement is especially important because technical rule breaches, dispatch disputes and licensing non-compliance may matter more in this market than textbook competition cases. In other words, surveillance is split between general competition law and sector-specific oversight.

The available enforcement tools are broad enough on paper. Authorities can investigate conduct, require information, review concentrations, impose administrative sanctions and, in serious cases, require remedial action. For electricity businesses, the real exposure often comes from a combination of competition risk and regulatory risk. A participant may be less worried about a cartel investigation than about losing its licence, breaching market rules, damaging its relationship with the system authorities or not being paid under its PPA.

The legal framework for generation projects is now more coherent than it was a few years ago, but it is still spread across multiple statutes and implementing instruments. The 2024 Electricity Law is the main electricity sector law, yet developers must also navigate laws relating to general investment, construction, land and water areas if relevant, environmental protection, marine and shipping if relevant, fire safety, and general corporate affairs and conduct. For large projects, procurement, bidding and public-private partnership rules may also become relevant, especially where the project is being developed through a state-led selection process. This makes Vietnamese power development a sequencing exercise as much as a legal interpretation exercise.

Technology-specific policy has become more important. LNG, offshore wind, onshore wind, solar, waste-to-energy and storage projects are all subject to the same broad legal regimes, but their real development paths differ materially. Offshore wind raises marine-space, survey and bankability issues. LNG-to-power raises fuel supply, fuel cost, supply pass-through, and terminal operation and interface issues. Storage raises revenue-model uncertainty. As a result, the overall framework may be common to all generation types, but project success still depends on how the specific technology fits within current policy priorities.

The 2025 implementing decrees have given developers a more updated rulebook for project development and licensing. They have also made clear that Vietnam expects projects to move from planning into construction under tighter procedural discipline. For developers, that is helpful in principle. The challenge is that more detailed rules do not automatically produce faster approvals if the underlying bottlenecks are central and local authorities do not know or have the capability to implement and, importantly, make decisions under these rules. Issues can range from local land clearance and compensation to grid congestion or unresolved commercial allocation of risk.

The approvals pathway for a commercial generation facility usually starts with planning rather than land. If the project is not recognised in the relevant power development framework or implementation plan, it is difficult to move the rest of the process forward with confidence. Once that foundation is in place, the developer typically moves through investor selection or project approval, investment registration, land or sea-area approvals, environmental approvals, construction approvals, grid connection arrangements, power sale documentation and, finally, the electricity operation licence. The order can vary in practice, but the process is cumulative and interdependent.

Public participation is most visible through environmental and land procedures rather than through a standalone energy hearing model. Environmental impact assessment can require consultation with affected communities and local authorities, and land acquisition or site clearance often brings its own local engagement challenges. In politically sensitive projects, those consultations can materially affect timing even if they do not change the project at a macro level. For coastal and offshore projects, stakeholder mapping is becoming even more important because fisheries, maritime use and national defence considerations can all become relevant.

Which authorities will need to be involved depends on the scale and nature of the project. The MOIT remains central from a sector perspective, but the Prime Minister, provincial people’s committees and specialist agencies can all play deciding roles at different stages. Developers therefore need to manage both the legal processes and institutional relationships. In Vietnam, an approval process is rarely a single-lane track through one regulator.

Approvals for generation facilities usually impose conditions on timing, technology, capacity and compliance rather than granting an entirely open-ended development right. A project approval may tie the developer to a specified capacity, site, technology choice, development and commercial operations schedule, and reporting obligations. Environmental approvals add mitigation and monitoring duties. Construction approvals set technical and safety conditions. The generation licence then focuses on operational capability, technical compliance and continuing legal obligations.

From a lender’s perspective, timing conditions are often the most sensitive. Vietnam has become increasingly focused on whether planned projects actually progress, especially after delays in several important project categories. If a project misses key milestones, the developer may face pressure to amend approvals, justify delays or in some cases risk adverse treatment in future planning or licensing discussions. That makes milestone management a legal issue, not just a project management issue.

Changes to the terms of approvals are possible, but are typically uncommon or not allowed if the change goes to the core of the project. A small technical update may be manageable. A change in technology, scope, capacity, development pathway, location, marine impact, fuel type or environmental footprint is much more significant. In practice, the more closely the change touches the original planning basis for the project, the more difficult and time-consuming the amendment process becomes.

Private generation developers do not usually enjoy direct eminent domain rights in Vietnam. They cannot simply condemn land in their own name for a power plant. Instead, land access is achieved through the state’s land administration system, including land allocation, land lease, land recovery and compensation processes, or through negotiated arrangements where the legal structure permits. This distinction is important because many foreign investors assume that once a project is approved, site control will follow automatically. In Vietnam, that is rarely the case.

Compensation and resettlement are governed primarily by land law and local implementation plans. The state determines the applicable framework, but the practical process is highly localised and can be one of the most challenging and time-consuming aspects of project implementation. Delays are common until previous land users agree compensation terms, where replacement land is not ready, or where multiple agencies need to co-ordinate site clearance. These are not minor administrative issues; they are often one of the most common and cause significant delays.

The commercial impacts can be significant. A power generation project may have a viable tariff and strong sponsor support, but still fail to complete construction and achieve commercial operations because of delays in site availability, land clearance and reaching agreement with previous land users on compensation. For that reason, project developers and lenders pay close attention to the land clearance strategy, the province’s track record and whether the approval package puts the risk mainly on the developer or leaves room for state assistance. Developers may often need to top up compensation packages brokered by local authorities to expedite reaching agreement with previous land users. Land risk and delays around site delivery are very real issues in Vietnam.

Vietnam does not yet have a deeply developed, technology-neutral decommissioning code for all types of generation assets. The legal obligations usually arise from a combination of environmental law, land obligations, project approvals, construction rules, waste management requirements and licence conditions. That means decommissioning is dealt with as part of broader project compliance rather than through a single comprehensive closure regime. The approach is workable, but it leaves important questions to be addressed case by case.

For conventional thermal and hydropower assets, the state’s expectations are relatively clear at a high level. Operators are expected to close facilities safely, manage residual environmental risks, dispose of equipment lawfully and restore or hand back land in accordance with the approved legal basis for the site. What is less clear is the extent to which long-term financial provisioning will be standardised across technologies. Vietnam has not yet adopted a uniform sector-wide decommissioning fund model for ordinary generation assets.

An exception was the BOT power scheme for thermal power projects developed by foreign developers. Some of the earliest projects developed and operated under that scheme have now been successfully handed back to EVN. The project concession agreements for these BOT power projects contained detailed requirements on project hand-over at the end of the concession period which were clear and enabled relevant parties to be able to achieve orderly and well-coordinated hand-overs.

Similar to many countries, decommissioning renewable electricity generation (other than hydropower) and storage facilities is not specifically prescribed for in Vietnam to any great extent. Solar projects raise panel recycling and land restoration issues. Wind projects raise turbine and foundation removal issues. Battery systems raise hazardous waste and fire-related disposal issues. Offshore wind and nuclear, if developed at scale, will require more tailored end-of-life rules than the current framework provides. As of mid-2026, there are few privately operated generation projects (other than under the previous BOT scheme – please see above – and some hydropower projects) that are at the end of their concession or operational lives, so the issues are yet to arise much in practice.

Transmission remains the most state-controlled part of Vietnam’s power industry. EVNNPT continues to function as the backbone national transmission owner and operator, and the legal framework still treats the high-voltage grid as strategic infrastructure. This is a fundamental feature of Vietnam. Private capital may help generation to scale up, but the national transmission system remains firmly tied to public control and operation.

Relevant laws include the 2024 Electricity Law, the construction and land regimes, environmental legislation, grid technical codes and the wider planning framework. Where storage is connected at transmission level or where private wire arrangements are developed for direct power supply, the picture becomes more nuanced. Even then, however, those private arrangements do not displace the state’s central role in the public grid. They exist alongside it.

Environmental review is generally required for major transmission works. Long routes, substations, forest areas, sensitive land use and populated corridors can all trigger substantial environmental and social issues, including in relation to resettlement. In practice, transmission development is often slowed less by pure engineering difficulty than by route approvals, land clearance, resettlement issues, and co-ordination across multiple districts and provinces. This is one reason why transmission has become such a strategic bottleneck in Vietnam’s energy transition.

Although transmission licences and non-state-built transmission assets are recognised in the legal framework, this should not be read as an open private transmission market. For ordinary public transmission, the system remains centred on EVNNPT, state planning and centralised grid operation.

The approvals process for transmission projects resembles other large infrastructure pathways but has its own practical sensitivities. Planning inclusion is critical, because the route and voltage level must fit the broader grid development programme. The project then typically moves through investment approval, land and route approvals, environmental assessment, construction approvals, technical design review and operational acceptance. If the asset is to be operated as part of the electricity system, licensing and operational co-ordination requirements also apply.

Public input is usually channelled through the environmental and land procedures rather than through an electricity-specific hearing process. Transmission routes can affect many land users without necessarily taking all of their land outright, so corridor restrictions and safety clearances become central issues. That often produces a wider social footprint than a compact thermal or solar site. A developer or state entity may therefore face extensive local engagement even where the formal legal steps look familiar.

Private wire projects under the DPPA model introduce a slightly different approval process. The key questions become where the private network starts and ends, who owns and operates it, how it interfaces with the public system and which approvals apply to the delivery point. These are manageable questions, but the answers are still developing in practice. As a result, private wire structures require careful legal and engineering design.

Transmission approvals usually contain detailed technical and route-based conditions. The approved route, tower or substation locations, safety corridor, environmental mitigation plan, construction schedule and applicable technical standards are all likely to be fixed or at least tightly controlled. Once the line is intended to operate as part of the national grid, co-ordination with system operation requirements becomes an equally important part of the approval framework. These are not formalities; small deviations can trigger significant follow-on approvals.

Route-related conditions are often the most commercially sensitive because they link directly to land compensation, clearance timing and engineering design. A route adjustment that looks modest on a map may affect forest land, residential land, river crossings or defence-sensitive zones. For that reason, route amendments are frequently more complex than sponsors first expect. The same is true for changes in voltage level or capacity, because those changes can affect the project’s role in the wider grid plan.

Amending approval conditions usually requires returning to the authority responsible for the original approval or to the authority now holding the relevant delegated power. The legal question is not simply whether an amendment is allowed; it is whether the proposed change alters the assumptions on which the original planning, environmental or investment decision was granted. If it does, the amendment can become almost as demanding as a fresh approval.

Even where a transmission project involves a licensed or non-state participant, the proponent does not obtain a private condemnation power. Land access remains a matter of Vietnam’s state land regime, and this is especially important for transmission lines because the safety corridor can affect many land users along the route. Access to land is achieved through state-led land allocation, land use restrictions, corridor establishment and mechanisms for compensating previous land users. For transmission line projects, this often means a combination of permanent land allocations for towers or substations and ongoing use restrictions across the broader safety corridor. The legal effect on landowners can therefore extend well beyond the small footprint of the physical structures.

Compensation for other land users depends on the legal status of the affected land and the specific impact on use rights. Owners or users may be compensated for requisitioned land, damage to land or other assets, relocation, business interruption or restrictions on use within the corridor, depending on the circumstances and the applicable compensation plan. The process is grounded in land law and local administrative implementation rather than in a bespoke electricity compensation code. That local dimension can make outcomes hard to predict.

For transmission line project planning, the important point is that transmission corridor issues can be just as material as outright site acquisition. A line may require only limited permanent land allocation but still create prolonged negotiations because many parties are affected by the corridor. The legal right to establish that corridor may exist, yet the timing of practical implementation can still be difficult. That is why transmission programmes are often sensitive from an ESG and local governance perspective.

Vietnam’s public transmission service is effectively monopolised through the state system. EVNNPT is the principal national transmission operator, and the legal and institutional design of the sector does not presently support competing public transmission networks in the ordinary sense. That monopoly is not simply commercial; it reflects national policy that treats transmission as strategic infrastructure tied to security, reliability and co-ordinated planning. For that reason, the monopoly is structural rather than accidental.

That said, recent reforms have opened the door for private infrastructure that sits outside the traditional public transmission model. The clearest example is private wire under the DPPA regime, where a renewable energy generator may deliver power to a large consumer through dedicated infrastructure rather than through the national grid. Those arrangements are important, but they should not be mistaken for a general right to compete with the national transmission network. They are exceptions built around specific commercial circumstances.

The distinction matters for investors. A private wire project may be feasible, but it does not mean a private party has acquired a franchise to offer open transmission services in a territory. Vietnam has not moved to that model. The public grid remains a regulated state-led system, and private infrastructure must be analysed within that context.

Transmission charges in Vietnam are highly regulated rather than freely negotiated. The cost of the transmission system is recovered through the regulated tariff structure and through the broader electricity pricing framework, not through open commercial bargaining between every generator and the transmission owner. The transmission owner is typically EVN or EVNNTP. That keeps the system administratively manageable, but it also means potential transmission line developers do not have the same freedom to shape network cost allocation as they might in a fully liberalised market.

For conventional grid-connected projects, transmission cost exposure is therefore usually indirect. It is reflected through the overall electricity tariff pricing rather than through a bespoke network access agreement on negotiated terms. For DPPA transactions across the national grid, however, these charges become more relevant. Parties need to understand which system charges, market fees, retail service charges or intermediary costs still sit in the transaction and who bears them. This is one of the key commercial issues in making DPPAs bankable.

The current framework is moving in the direction of greater cost transparency, but implementation remains gradual. DPPAs are one of the most important developments for corporate electricity users. The 2026 regulatory updates make DPPAs more practical. Decree No 243, introduced in June 2026, clarified that the mechanism covers renewable energy generators, large electricity consumers and retail electricity units in industrial-zone and similar models. It also expanded eligible large consumers beyond production customers to include users such as data centres, electric vehicle charging stations and battery swapping facilities, subject to the relevant connection and eligibility requirements. Circular No 29 of the MOIT in 2026 is also important. It reduced the average monthly consumption threshold for large electricity consumers using the direct transmission DPPA model from 200,000 kWh to 20,000 kWh, while keeping the 200,000 kWh threshold for the national-grid model. It also clarified the treatment of renewable plants participating in virtual DPPAs as direct market participants, while plants supplying through direct transmission DPPAs are treated as indirect participants.

Vietnam does not yet provide open access in the same sense as may be familiar in relation to mature or open transmission markets. Access to the grid exists, but it is firmly managed by state instrumentalities through planning, technical capacity, dispatch rules, licensing and the structure of the electricity market itself. A project cannot assume that satisfying one legal requirement creates a free-standing, enforceable right to transport power on demand. Access is real, but it is conditional and system-based.

Generators and large users can connect to the grid if the legal and technical requirements are met, and the DPPA framework gives large users a more direct route to contractual access to renewable supply. Even so, those rights remain subject to the physical and institutional limits of the system. Congestion, curtailment, dispatch instructions, metering requirements and settlement rules all shape what access means in practice.

The non-discrimination principle is therefore best understood in context. Vietnam does not openly state that access can be arbitrary, and the legal framework is moving towards more transparent market participation; however, equal treatment remains constrained by planning status, connection availability – including how many existing generators may be putting electricity into the grid in a particular location – and the operational needs of a centrally managed system. The practical message is that access rights are meaningful only when read together with the system rules and the actual capacity of the network in a relevant location.

Distribution is still largely organised through EVN’s regional power corporations and affiliated structures. Vietnam does not have a truly liberalised electricity distribution market. Although Vietnamese law contains a licensing regime for electricity distribution, public distribution is not, in practice, a market in which private operators generally participate. EVN and its power corporations carry out public distribution, with non-EVN activity limited to narrow cases such as industrial parks or other bounded networks.

Public electricity distribution is still carried out in practice by EVN, through its regional power corporations. EVN is state-owned and remains the central entity for public distribution and retail supply. The governing framework includes the 2024 Electricity Law technical regulations, construction and land laws, environmental rules and retail tariff rules. In ordinary consumer supply, the system remains utility-driven with no change or choice. In industrial zones, private campuses and specialised commercial developments, the picture is more varied.

This is the part of the sector where microgrids, campus supply and private network solutions are becoming more relevant. Vietnam has not yet created a fully separate microgrid code, but the combination of DPPA reforms, distributed energy growth and industrial demand is pushing policy in that direction. The same is true for storage at distribution level, which is increasingly seen as part of demand management and reliability rather than only as a generation-side tool. The legal framework is therefore widening, even if it still looks utility-centred in form.

For privately owned power generators, distribution is less about acquiring a liberalised retail business and more about identifying the permitted boundaries of private supply. A generation project serving an industrial park or large integrated site may have more room for private infrastructure and supply arrangements than a generation project selling to EVN.

As mentioned above, public distribution is carried out in practice by EVN and its power corporations, and in practice, Vietnam does not currently have a generally open market for competing distribution utilities. A non-EVN entity may hold a distribution or retail licence only for a limited, defined scope, for example within an industrial park or a similar bounded network. Where that applies, the proponent would need the usual project, land, construction, fire safety, environmental and electricity operation approvals. Public hearings are not generally required for electricity distribution licensing, although public consultation may be required if the project is subject to an environmental impact assessment or land recovery process. The electricity operation licence is granted by the competent licensing authority, not merely recommended to another body. The licensing process itself may be completed in weeks after a complete filing, but the overall project approvals usually take several months or more, and may take longer if land or environmental issues are involved.

Vietnamese law recognises electricity distribution as a licensed activity, but this should not be read as meaning that Vietnam has an open private distribution market. In practice, EVN remains responsible for public distribution, while non-EVN distribution is generally confined to specific closed or semi-closed networks, such as industrial parks.

For that reason, it is not usually relevant to raise a question on the process for a private proponent seeking to operate public distribution facilities. Where a distribution licence is issued, the terms are mainly regulatory and technical. They are not typically negotiated commercial conditions.

As mentioned above, while a distribution licence is possible under Vietnamese law, the practical market position remains that EVN undertakes public distribution, and private participation is exceptional and limited in scope. This is important because land access issues for public distribution projects usually arise in the context of EVN or grid development backed by the state, rather than private utility franchises.

Land access is handled through the state land regime. This may involve land allocation, land lease, route approvals, agreements with land users, electricity safety corridors, or state land recovery where the project qualifies. For EVN and other state-backed grid projects, land recovery is carried out by the competent state authority, not by the project owner directly. The competent authority approves the land recovery and the compensation, support and resettlement plan.

Public electricity distribution in Vietnam is effectively controlled by EVN, a state-owned enterprise, through its regional power corporations. Non-EVN distribution exists only in limited settings and should not be treated as evidence of a liberalised distribution market.

Vietnamese law does allow distribution and retail licences within defined scopes. However, that does not mean there is an open market for competing distribution utilities. In practical terms, EVN remains the public distribution monopoly.

Electricity distribution charges and retail terms are state-regulated. EVN and its power corporations apply tariffs set under the national electricity pricing framework. They do not freely negotiate distribution charges with ordinary customers.

The Prime Minister sets the tariff structure and price bracket. The Government sets the mechanism for adjusting the average retail electricity price. The MOIT supervises and approves key pricing matters. EVN calculates and implements price adjustments under that framework.

This is not a public rate-case model. It is a regulated tariff model based on electricity sector costs, including generation, transmission, distribution, retail, system operation and regulated profit.