Thai power plan outlines four scenarios, tariffs up to 4.58 baht by 2050
Thailand will consult on four power scenarios on September 8, weighing electricity costs, renewable energy and carbon capture through 2050
- The draft Power Development Plan (PDP 2026) projects electricity tariffs of 4.11–4.58 baht per unit by 2050, reflecting costs not included in previous plans for transmission upgrades to accommodate renewable energy and carbon capture and storage (CCS).
- The government has proposed four scenarios for public consideration as Thailand works towards net-zero emissions by 2050, each with different clean-energy shares, costs and electricity tariffs.
- Option 1, the Base Case, has the lowest average tariff at 3.8267 baht per unit but would not achieve net zero.
- Option 2, Net Zero by CCS, relies primarily on carbon capture technology and has the highest average tariff at 3.8859 baht per unit.
- Option 3, Net Zero by Renewable Energy (RE), has the highest clean-energy share at 89% but requires substantial grid investment. Option 4, Net Zero by RE & CCS, combines renewables and carbon capture to balance costs and supply security.
Electricity tariffs in Thailand could reach 4.11–4.58 baht per unit in 2050 under four scenarios in the draft Power Development Plan, as planners weigh the cost of integrating renewable energy and capturing carbon emissions.
The Energy Policy and Planning Office (EPPO), under the Energy Ministry, will open public consultation on Tuesday (September 8, 2026) on the proposed Power Development Plan for 2026–2050, known as PDP 2026.
Average retail tariffs over 2027–2050 are projected at 3.83–3.89 baht per unit, depending on the scenario chosen. These period-wide averages are lower than the projected rates at the end of the plan.
The four cases compare different combinations of clean energy, carbon capture and conventional generation. The lowest-cost baseline would not achieve the 2050 net-zero emissions target, while the other three examine alternative routes towards it.
Grid upgrades and carbon capture add costs
The draft incorporates two cost categories that were not included in previous plans.
- Renewable-energy integration costs — Upgrading transmission infrastructure to accommodate variable electricity output from renewable sources.
- Carbon capture and storage costs — Deploying carbon capture and storage (CCS), with an assumed cost of US$135 per tonne of carbon.
The choices will affect both electricity prices and the infrastructure needed to maintain reliable supplies.
The draft also responds to five changes in electricity demand and the wider business environment.
- Growing industrial demand for clean energy.
- Rapid expansion of data centres and artificial intelligence (AI).
- More consumers generating their own electricity, known as prosumers.
- The transition to electric vehicles.
- New international trade requirements, including the Carbon Border Adjustment Mechanism (CBAM).
Four scenarios for public consideration
The draft sets out the following options.
- Base Case — Clean energy would account for 65% of the mix, with greenhouse gas emissions of 51.5 million tonnes. Its average tariff of 3.8267 baht per unit is the lowest of the four cases, but it would not meet the net-zero target.
- Net Zero by CCS — This scenario relies primarily on carbon capture, covering 32 million tonnes, while retaining the use of domestic natural gas. It carries a risk of liquefied natural gas (LNG) imports reaching 2,455 million cubic feet per day. Its average tariff of 3.8859 baht per unit is the highest among the four options.
- Net Zero by RE — The renewable energy (RE) scenario would raise the clean-energy share to 89%, the highest of the four cases, and bring emissions down to 16.6 million tonnes, the lowest level. However, it would require the largest grid-upgrade investment, at up to 700 billion baht, to manage variable renewable output.
- Net Zero by RE & CCS — This combines renewable energy with carbon capture and storage. The draft presents it as a middle course intended to balance costs and electricity-supply security.
Common investment programme through 2037
All four cases share the same initial infrastructure programme during the plan’s first 12 years, from 2026 to 2037, before their development paths diverge more clearly after 2037.
The proposed additions total 50,900 megawatts (MW), including both electricity generation and battery storage.
- Natural gas-fired power plants — 9,100MW.
- Small modular nuclear reactors (SMRs) — 300MW.
- Solar power — 24,300MW.
- Wind power — 2,700MW.
- Battery energy storage systems (BESS) — 14,500MW.
The draft also changes how planners assess system reliability. Instead of relying principally on reserve margins, it adopts Loss of Load Expectation (LOLE), with a threshold of no more than 1.0 day per year.
LOLE assesses the expected periods when available supply may be insufficient to meet demand. It is a planning measure, rather than a prediction that consumers will experience a full day of blackouts. EPPO has explained that the approach better accounts for changing demand and uncertainty in electricity generation.
Private businesses would also take a more active role in the electricity system through direct power purchase agreements (Direct PPAs) and third-party access (TPA) to electricity networks.
The National Energy Policy Council (NEPC) approved an expansion of these arrangements on July 15, 2026, opening the way for industrial users and data centres to buy green electricity directly from producers.
The September 8 consultation will allow the public, businesses and other stakeholders to comment on all four scenarios and submit further proposals. EPPO will use the feedback to revise the draft before presenting it to the NEPC for consideration.
