PDP8: Vietnam’s Plan to Double Its Grid Without Coal

PDP8 is the document that decides whether Vietnam’s manufacturing boom can continue, and it has been rewritten twice in two years because the first version was already too small. Every power plant in Vietnam must appear in the plan before it can be built, so the plan is not a forecast but a permission list, and the fights over what gets included — which provinces get LNG terminals, whether offshore wind counts by 2030, how much coal survives — are fights over tens of billions of dollars of investment. This article explains what the plan says, why it changed, how it is meant to be financed and where it is most likely to fail. It is part of the Vietnam Company Stories hub.

Why did it take four years to approve PDP8?

The plan was delayed from 2019 to 2023 by a fundamental disagreement over coal. Provinces and state enterprises wanted more coal plants included, international lenders and the climate commitments Vietnam made at COP26 in 2021 required fewer, and each draft had to be rebalanced as renewables surged and the cost assumptions changed.

The seventh plan, from 2011 and revised in 2016, had been built around coal, with a target of more than 55 gigawatts of coal capacity by 2030. By 2019 it was clear that most of the planned plants would not be financed: Japanese, Korean and Chinese lenders were retreating from coal, and the solar rush described in the solar boom story had added capacity the planners had not anticipated. The Ministry of Industry and Trade began drafting PDP8 with a dramatically different mix.

Then, in November 2021 at COP26, Prime Minister Phạm Minh Chính committed Vietnam to net-zero emissions by 2050 and to phasing out unabated coal by the 2040s. That commitment forced another rewrite. A year later, in December 2022, the Just Energy Transition Partnership with G7 donors set a 2030 coal cap of about 30 gigawatts and a target of 47 percent renewables. Each draft — there were at least a dozen — had to reconcile these external commitments with domestic demand forecasts that kept rising and with a list of provincial projects that kept lobbying for inclusion.

The final 2023 version was a compromise. It kept the coal plants that were already under construction or had firm financing, added a large LNG fleet as the bridge fuel, set an ambitious onshore wind target and a cautious solar target, and included a 6-gigawatt offshore wind target by 2030 that almost nobody in the industry believed was achievable.

What did the original 2023 plan actually say?

Decision 500 targeted about 150 gigawatts of installed capacity by 2030, comprising roughly 30 gigawatts of coal, 37 gigawatts of gas (15 from domestic fields and 22 from imported LNG), 29 gigawatts of hydro, 22 gigawatts of onshore wind, 6 gigawatts of offshore wind, and about 13 gigawatts of utility solar plus rooftop, with a total investment need of about $135 billion.

The logic of the mix was balance. Coal was capped at what was already committed. LNG was to be the flexible fuel that could run at night and in the dry season when hydro and solar could not. Onshore wind was favoured over solar because its output profile complements solar and because the central and southern coastal provinces had strong wind resources. Solar was deliberately held down, the ministry having concluded that the 2019–2020 wave had already saturated the grid’s ability to absorb midday generation without storage.

The plan also laid out transmission: new 500 kV corridors, including the north-south backbone reinforcement that was later built at record speed after the 2023 blackouts described in the EVN story, and it set a formal principle that generation should be located near demand, an implicit rebuke to the solar clusters in remote south-central provinces.

For 2050, the plan envisaged 490 to 573 gigawatts, with coal eliminated, gas plants converted to hydrogen or fitted with carbon capture, and renewables supplying two-thirds or more of generation. Those numbers were aspirational, but they signalled to investors the direction of policy: a very large, long-lived market for renewables and grid equipment.

Why was the plan revised so soon, and what changed in 2025?

The 2025 revision followed a change in political ambition: the leadership under General Secretary Tô Lâm set a goal of 8 percent growth in 2025 and double-digit growth through 2030, and the 2023 plan’s demand forecast could not support that. Decision 768 in April 2025 raised the 2030 capacity target by up to 60 percent.

The revised numbers are striking. Solar was lifted from about 13 gigawatts to a range of 46 to 73 gigawatts, a reversal of the 2023 caution, justified by falling battery costs and the new self-consumption and direct purchase rules that let factories build their own supply. Onshore and nearshore wind rose to 26 to 38 gigawatts. Battery storage, barely present in the 2023 plan, was given a target of 10 to 16 gigawatts. Offshore wind was pushed out to 6 to 17 gigawatts by 2035, an acknowledgement that no project would be turning by 2030.

Nuclear returned. The National Assembly had voted in November 2024 to restart the Ninh Thuận programme, and the revised plan targets 4 to 6.4 gigawatts of nuclear capacity between 2030 and 2035, with EVN assigned the first plant and Petrovietnam the second. Given that no Vietnamese nuclear plant has ever been built and the earlier programme with Russia and Japan was cancelled in 2016 over cost, the 2035 date is regarded by most observers as a statement of intent rather than a schedule.

Coal was, quietly, allowed a little more room. The revised plan kept the roughly 31-gigawatt coal ceiling but extended the operating lives of some existing plants and left the door open for those under construction to complete. LNG stayed at about 22 gigawatts, though with a longer list of named projects than could realistically be financed.

How is a $136 billion plan supposed to be financed?

The plan assumes that the state and EVN finance the grid and a minority of generation, while private domestic investors, foreign developers and development banks finance the rest. In practice, that means the plan depends on power purchase agreements being bankable enough to attract international project finance at scale, which they have not historically been.

The state’s own capacity is limited. EVN, the single buyer, was loss-making in 2022 and 2023 and its balance sheet cannot carry the grid programme without concessional lending from the World Bank, the Asian Development Bank, Japan’s JICA and Germany’s KfW. Petrovietnam is financially stronger and is building the first LNG-fired plants and terminals, as described in the Petrovietnam story, but its capital is committed to gas, oil and now nuclear.

Domestic private capital has proved willing but shallow. The solar rush showed that Vietnamese conglomerates and banks could mobilise several billion dollars quickly for projects with a fixed tariff, but those same investors were burned by curtailment and retroactive tariff challenges, and the domestic bond market has been fragile since the 2022 property-linked crisis. Foreign developers have the capital but have consistently asked for terms — government guarantees, international arbitration, protection from curtailment, dollar indexation — that the government has refused to write into the standard EVN contract.

The Just Energy Transition Partnership was meant to bridge this gap with $15.5 billion of concessional and commercial finance, but as the offshore wind and JETP story explains, disbursement has been slow and the terms on offer have been mostly loans rather than grants. The realistic financing picture for PDP8 is a patchwork: development bank money for the grid, Japanese and Korean corporate capital for LNG, Thai and Singaporean capital for renewables, and Vietnamese conglomerates for whatever the state allocates to them.

Why is LNG the plan’s biggest gamble?

PDP8 relies on about 22 gigawatts of LNG-fired capacity by 2030 to provide flexible, dispatchable power as coal is capped and renewables grow, but as of mid-2026 only the first plant, Nhơn Trạch 3 and 4, was operating, and most of the remaining projects were stuck on pricing terms with EVN.

The LNG chain is entirely new for Vietnam. It requires import terminals, of which only Thị Vải near Ho Chi Minh City was operating by 2024, regasification, pipelines, and plants with turbines from GE, Siemens or Mitsubishi. Each link has to be financed separately, and the plants only make sense if the terminal is built, while the terminal only makes sense if the plants are built. Petrovietnam has resolved this at Nhơn Trạch by owning both; elsewhere, projects led by foreign consortia such as AES at Sơn Mỹ or ExxonMobil at Hải Phòng have struggled to reach financial close.

The central obstacle is the pass-through of fuel cost. LNG is bought at world prices, in dollars, on long-term or spot contracts, and the plant’s economics depend on EVN agreeing to buy a minimum volume of power at a price that reflects the fuel. EVN, constrained by a regulated retail tariff, has resisted committing to high minimum offtake at gas-linked prices. The 2024 Electricity Law and its 2025 decrees introduced a framework for minimum offtake of about 65 percent over a plant’s early years and a mechanism to pass LNG costs into the tariff, but the details remain contested project by project.

The timing problem is now acute. A combined-cycle gas plant takes three to four years to build after financial close; a terminal takes a similar period. Projects that have not closed by 2026 will not be operating by 2030, which means that the gap PDP8 assigned to LNG will in practice be filled by running existing coal plants harder, importing power from Laos and China, and adding solar with storage faster than anyone planned.

What role does coal still play?

Coal remains the backbone of Vietnamese generation through 2030, supplying roughly 45 to 50 percent of electricity from about a third of installed capacity, and the plan’s coal cap of around 31 gigawatts means that existing plants will run harder, not less, as demand grows.

Vietnam built its coal fleet fast in the 2010s: large plants at Vĩnh Tân, Duyên Hải, Mông Dương, Nghi Sơn and Vũng Áng, financed by Chinese, Japanese and Korean contractors and lenders, and fed by domestic coal from Vinacomin in the north and imported Indonesian and Australian coal in the south. Those plants are young, with operating lives extending into the 2050s, and there is no credible mechanism yet to retire them early. The JETP discussion of early retirement has produced studies but no funded transactions.

The domestic supply of coal is itself a constraint. Vinacomin’s mines in Quảng Ninh are deep and expensive, and the country became a net coal importer in the mid-2010s. Fuel shortages at northern plants contributed to the 2023 blackouts, and the government has since pressed Vinacomin and the plants to hold larger stockpiles. Imported coal prices, which spiked in 2022, feed straight into EVN’s purchase costs and therefore into the political tariff debate.

Coal’s role gives the plan a hidden dependency: the transition it describes is only clean if the new capacity arrives. In the years before it does, Vietnam’s emissions will continue to rise, and the international partners who signed the JETP will have to decide whether to keep financing a country whose coal generation grows in absolute terms while its share falls.

What does PDP8 mean for founders, investors and operators?

For businesses in Vietnam, PDP8 is a map of where the state wants capital to go and a warning about where supply will be tight. The practical implication is that being inside the plan is a licence to operate, and that the north will remain the region of greatest supply risk until new gas, nuclear or transmission arrives.

For power developers, the revised plan is generous on paper and stingy on mechanism. It authorises tens of gigawatts of solar, wind and storage, but the price a project will receive is set through negotiation with EVN under ministerial ceilings, and the provincial allocation of projects is a political process. Developers with local partners, land already secured and grid capacity confirmed have a strong position; those arriving with capital alone do not.

For manufacturers, the plan is the reason to take energy security seriously in site selection. Companies that need firm, clean power — semiconductor assemblers such as Intel in Saigon, data centre operators, apparel makers with brand commitments — are increasingly signing direct power purchase agreements, installing rooftop solar with storage, and choosing parks in the south or in northern provinces adjacent to new 500 kV substations. The story of how China Plus One investment flowed into Vietnam is, in part, a story about cheap power; sustaining it is a PDP8 problem.

For the state, the plan is a test of execution. Vietnam has proven that it can build transmission lines in months when the leadership demands it, and that it can attract billions of dollars into renewables when the tariff is right. It has not yet proven that it can write a bankable long-term contract, finance a gas or nuclear fleet, or manage the intermittency of tens of gigawatts of solar. PDP8 assumes all three. The decade will show which assumptions hold.

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