Vietnam: new year, new power plan

Summary

Vietnam is revising their long-term power development plan less than two years after its release, as previous capacity expansion targets have become unrealistic.

The urgency to fill immediate supply gaps leaves planners with limited options: a razor-sharp focus on renewables, battery storage, and electricity imports from now until 2030.

The power development plan revision is a reminder of how short-lived energy plans and their underlying models can be. Power system modelling tools will become increasingly important to proactively assess how the future power mix responds to an ever-evolving set of assumptions.

Vietnam’s energy planners have gone back to the drawing board, revising the country’s master power development plan, PDP8. Released in 2023, it was meant to last at least five years, laying out the national power system blueprint up to 2030. However, the core targets have quickly proven to be unattainable. The government has struggled to negotiate a balance between an investable framework for gas and renewable energy projects, and the long-term affordability of electricity for consumers. With key technology choices in flux and a disheartening policy vacuum on most fronts, the development of new generation capacity has stalled compared to the expansionary period leading to 2021.

Catching up to demand

Electricity demand is now rebounding in Vietnam to pre-pandemic levels. Annual electricity sales soared by 9.2% from 2023 to 2024, which might be the fastest growth in Southeast Asia. Peak demand also reached nearly 49 gigawatts (GW), up 5.6% year-on-year. However, the amount of large-scale generation capacity expected to reach the commissioning stage in the next 2-3 years is limited. If such growth continues, the risk of power shortages until 2030 will only worsen without quick action.

The pressure is mounting on the energy ministry (MOIT) to tackle the following question head-on: which system development options could Vietnam tap into to fill immediate supply gaps, and with the fewest execution, cost, energy security, and climate risks in the long-term?

Vietnam is confronting this supply challenge at a time when the national power system has been under strain for years. Since the COVID-19 pandemic, the state utility Electricity of Vietnam (EVN) has been forced to rely on a combination of contingency measures to tackle widespread blackouts. The critical months usually run from May to July when peak consumption spikes under the summer heatwaves and hydropower — a key generation source in the northern region after coal — is less dispatchable due to seasonal water shortages. To manage the problem, EVN has had to intervene with demand response measures such as load shedding and load shifting calls to large industrial customers, as well as system optimisation measures such as charging up the hydroelectric reservoirs in the pre-summer months.

Albeit overdue, the authorities have also prioritised grid development, most notably with the expedited completion of the 500kV circuit 3 North-South transmission line which spans 520km to provide reinforcements from the central region to the north. Electricity imports from neighbouring China and Lao PDR have also increased. In the former case, this involved fast-tracked grid connection with China’s Guangzi region on the northern border.

Limited choices

The urgent need to address such significant supply gaps by 2030 leaves energy planners with a constrained menu of choices. Speed is of the essence, but potential technologies differ in how quickly they can be deployed, how suitable they are for Vietnam’s existing or near-term energy infrastructure (for instance, grid network and gas terminals), and how easily they can mobilise financing at scale, to name a few. For example, nuclear power has been approved for re-inclusion in the updated PDP8 but even if successfully pursued and realised, it would hardly make an impact on supply before 2035.

Yet assessing the technologies through these filters helps narrow down the most promising options for Vietnam in the short term. This is already evident in the recent draft of the new PDP8, released for public consultation earlier this month. The revised plan puts heavy emphasis on utility-scale solar, onshore, and nearshore wind power to drive new generation capacity. However, these will now need to be supported by increased storage capacity and flexible generation sources.

This shift reflects the lessons Vietnam has learnt from expanding its generation fleet and managing a more diverse, renewables-rich power mix, as well as the bets that the planners feel most comfortable making in volatile times.

What does our modelling show?

The system improvements Vietnam hopes to see from these policy options also align with recent TransitionZero research. Our open access power systems model TZ-APG v1 investigated the changes to Vietnam’s power mix under different regional interconnection scenarios while meeting national renewable energy targets.

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For full details on TZ-APG v1 model design and constraints, see here.

More renewables, bigger batteries

In our TZ-APG v1 model, the results suggest that Vietnam’s ambitious variable renewable energy targets under the current PDP8 (such as 6 GW of offshore wind and 22 GW of onshore wind by 2030) would need to be accompanied by sizable storage capacity to ensure system reliability and a least-cost outcome. By the modelled year 2035, battery storage — whether in the form of plant- or system-level installations — would need to reach around 36 GW if the PDP8 renewable energy targets are to be met. This remains largely unchanged even in the case of enhanced grid connections with the region.

Unfortunately, batteries have been largely overlooked despite the challenges of operating a power system with 26% variable renewable energy. Vietnam currently lacks a regulatory and pricing framework for battery energy storage systems (BESS) to provide ancillary services, which has hindered interest in PDP8’s modest target of 300 MW BESS by 2030.

On the other hand, policies governing renewables procurement do not distinguish between renewables-plus-storage (firm) and renewables-only (non-firm) solar and wind power. This is trailing the practices observed in nearby markets such as Thailand and Malaysia which offer better pricing for the former. The implications are two-fold: on the one hand, there is an absence of procurement schemes that incentivise renewables-plus-storage development; and on the other hand, EVN misses out on the opportunity to add such sources into the system that are just as scalable but less operationally challenging than non-firm sources.

The new BESS target in the revised PDP8 will be crucial for project development and capacity allocation, but this must be adequately supported by conducive follow-on policies and incentives.

Cross-regional transmission back in the spotlight

The resurgence of utility-scale solar at the massive scale proposed in the new PDP8 brings the issue of inter-regional transmission and grid readiness back into focus. While batteries can address intermittency challenges, the grid remains essential to deliver renewable electricity from the central and southern regions to the supply-deficient north. This should be a shared concern among all developers, including those that sell directly to EVN, and those involved in corporate power purchase schemes (commonly known as DPPAs in Vietnam) with industrial off-takers in the northern manufacturing hub.

Our TZ-APG v1 model shows that Vietnam’s domestic transmission lines are potentially the busiest in the region, given the two load centers in the north and south and the development of renewable energy in the resource-rich central region. This occurs regardless of the level of integration in the regional grid.

The updated 2030 solar target is promising and key to enabling a new wave of greenfield projects. However, it must be paired with a clear commitment and roadmap for transmission and distribution network upgrades. The good news is that, compared to the original PDP8, MOIT planners appear to have softened their stance on regional self-sufficiency and are now signalling support for long-distance transmission— which aligns with the development of generation capacity in resource-rich regions.

Import acceleration

Electricity imports from Lao PDR remain a key part of Vietnam’s strategy to relieve capacity stress. The government has made noticeable efforts to address policy gaps to expedite project development and approvals. In 2024, MOIT released the much-anticipated tariff caps on imported wind power ($0.064/kWh) and hydropower ($0.068/kWh) for projects operational between 2026-2030, which are the key basis for offtake negotiations between project sponsors and EVN.

Proposals for new wind power imports have been gaining momentum. Several new Laotian projects, including the 250 MW Truong Son and 300 MW Savan 1, were approved last year and are slated for completion by late 2025. Critically, the high-voltage transmission projects needed to connect these wind power projects to the national grid on this side of the border are already underway.

Yet, there remains significant room for new import capacity from Lao PDR. We estimate that less than half of the 8 GW target for 2030 has been allocated, and the draft PDP8 has raised the goal to 10 GW. Assumptions about the scale and speed at which such capacity will actually be realised in the coming years will significantly impact projections for future system development needs.

In the TZ-APG v1 model, we examined the impact of increased import capacity from Lao PDR to Vietnam’s cost-optimised power mix. Among all the technologies, gas power generation proved to be the most sensitive to increased imports from Lao PDR. In other words, Vietnam could cut down on gas power capacity build-out if more low-cost imports from Lao PDR are enabled.

Persistent supply gaps in northern Vietnam will push the authorities to approve more cross-border projects. Compared to domestic renewables projects, cross-border projects benefit from a more favourable regime, including a more attractive power purchase agreement (PPA) framework coupled with high-level political support and facilitation of associated transmission projects. This boosts the likelihood that they will be developed and completed on schedule.

On another note, it remains a common practice that imported electricity from Lao PDR follows the independent power project IPP-to-grid model, in which offtake from a dedicated generator is bound by a 20 to 25-year PPA with fixed tariffs and a balanced risk allocation between EVN and the project sponsor. Such favourable arrangements carry noteworthy implications for system management in the form of long-term offtake obligations or priority dispatch that could potentially outcompete domestic sources of supply, just as EVN is pushing for a more flexible offtake regime for projects built at home.

Gas backloaded

Vietnamese authorities have now conceded that the original goal of installing 22 GW of new LNG-based power capacity and 8 GW of new domestic gas power capacity by 2030 will not be met. The draft PDP8 has shifted part of these targets to 2035 but local planners remain optimistic that the majority will enter the system within the next five years.

But this optimism is not in sync with the existing regulatory vacuum. While it is true that Vietnam inaugurated its maiden LNG import terminal (1 MMTPA Thi Vai) in 2023, and the first LNG-based power plants (1.6 GW Nhon Trach 3 & 4) are likely to be fully commissioned this year, these projects are backed solely by the energy state-owned company Vietnam Oil and Gas Group with corporate financing arrangements and did not follow commercially-acceptable project development practices. For example, the construction of Nhon Trach 3 & 4 plants was over 90% complete by the time it managed to sign a PPA with EVN in October 2024.

Meanwhile, the majority of LNG power projects in the pipeline are IPPs, most of which are fully and a few partially sponsored by private companies. Unlike state-owned projects, these will need to secure financing and contractual agreements upfront, making it unlikely that these will be able to follow the project development and contractual templates of Nhon Trach 3 & 4.

But delays are just one issue. Current policy priorities favour technologies and projects with short lead times. The proposed radical changes to the power mix by 2030 — particularly the scaling up of solar, wind power and supporting infrastructure — raises existential questions about the optimal size and role of gas in the system in the 2030s and beyond. Faced with a larger fleet of renewables, project sponsors and their lenders will have an even harder time assessing the viability of LNG projects in the long term.

Modelling change

The PDP8 revision comes as little surprise to those following Vietnam’s power sector, given the slow pace of PDP8 implementation so far. However, it serves as yet another reminder of the all-too-frequent gap between aspirational policy targets and what the state can actually execute. It is also indicative of how short-lived master plans, and their underlying models and inputs can be in uncertain times. In the case of Vietnam, PDPs have been weak indicators of how the national power system will shape up and insufficient in guiding sound investment decisions.

The burden of this gap and uncertainty is falling heavily on project sponsors and their lenders. Instead of relying on national plans as the north star, ad-hoc and periodically adjusted model runs like those provided by TZ-APG will become essential for well-informed, up-to-date assessments of the power system’s outlook.