Draft Power Development Plan 2026–2050 (PDP2026): A Structural Reorientation of Thailand’s Generation Mix and Implications for Investors, Developers and Large Consumers (Thailand)

1. The Four Scenarios

The draft does not propose a single pathway. It sets out four alternative development scenarios and asks stakeholders which balance Thailand should adopt. All four share the same demand forecast and a broadly similar near-term build programme; they diverge principally from the mid-2030s, when the choice between continued gas use with carbon capture, and large-scale renewables with storage, becomes material.

The electricity tariff differs by less than 0.06 THB per unit (about 1.5%) across all four scenarios, a gap smaller than the uncertainty in the underlying forecasts. The columns that actually differentiate them are gas demand and grid investment. In other words, what each case commits the country to in terms of imported fuel exposure on the one hand, and network construction on the other.

The EPPO has publicly indicated a preference for Case 4, roughly 73% clean energy and 27% fossil fuels reasoning that it continues to use Thailand’s own Gulf of Thailand gas, limits exposure to imported liquefied natural gas prices, and meets climate targets without the very large grid spending implied by Case 3.

2. Capacity Build-Out and Retirements

New capacity, 2026–2037: 50,900 MW

Approximately 47,547 MW of existing plants are scheduled to retire over the corresponding period. A further 32,805–33,305 MW of renewables and new technologies are to be deployed by 2050, including biomass, biogas, small hydropower, demand response, and distributed generation.

Battery storage is not new to Thailand in absolute terms: The Electricity Generating Authority of Thailand (“EGAT”) operates grid-connected battery systems, and batteries have been procured principally as a component of hybrid solar-plus-storage projects under the Energy Regulatory Commission (“ERC”) feed-in-tariff rounds. Reported built-or-awarded storage capacity nonetheless remains well below the level this plan contemplates. What has not yet been established is a framework for standalone storage, a battery contracted to provide balancing and capacity services to the system generally, rather than to store the output of one specific generator. How such capacity would be procured, owned and remunerated, is a question the draft plan leaves to subsequent regulation.

3. Direct Sales and Grid Access

The PDP2026 embeds a liberalisation agenda previously advanced only through pilot instruments:

• Direct PPA via TPA: The NEPC resolution of 15 July 2026 extends the Direct PPA mechanism through the TPA regime to large consumers and data centres, with the Energy Policy Administration Committee (the “EPAC”) designated as the selecting and supervising authority. This builds upon the ERC’s draft Direct PPA and TPA Code framework developed with the EPPO, the Board of Investment of Thailand (the “BOI”) and the three utilities.
• Digital grid and metering: 100% smart meter deployment for large customers; development of Virtual Power Plant (“VPP”) and Demand Response markets, converting large consumers from passive load into balancing service providers.
• Grid modernization: Revision of the Smart Grid Master Plan for 2027–2050 to accommodate multi-directional flow, grid renovation of end-of-life assets, and system-strength provision via static synchronous compensator (“STATCOM”), transmission-connected batteries and synchronous condensers under the renewable energy (“RE”) integration cost line item.

4. Nuclear and Carbon Capture

5. Implications for Stakeholders

Gas-fired generation and LNG infrastructure: Gas demand in 2050 is estimated to range from approximately 794 MMscfd under Case 3 to approximately 2,455 MMscfd under Cases 1 and 2, with Case 4 at approximately 1,904 MMscfd, roughly a threefold difference between the highest and lowest cases. The EPPO has characterised the Case 1 and 2 levels as carrying elevated LNG import exposure, while presenting Case 4 as making full use of domestic gas. LNG terminal, regasification and shipping investors should stress-test throughput against Case 3 and seek explicit transitional treatment in the final plan. New combined-cycle capacity should additionally be assessed against the possibility of carbon-capture-ready design conditions being attached at the procurement stage.

Solar and wind development: The approximately 27 GW of solar and wind programmed for 2037, plus 32.8–33.3 GW of policy-driven RE and new technology to be deployed by 2050, sustains a deep pipeline. However, the evening-peak profile means standalone solar without storage will face declining capacity value and increasing curtailment risk. Developers should expect the hybrid solar-plus-storage offerings and scrutinise curtailment compensation and deemed-generation provisions in forthcoming PPA templates.

Storage and grid technology: The 14,500 MW allocation is the largest single new opportunity in the plan, but it is an opportunity defined by a document that has not been adopted and by rules that have not yet been made. With the consultation period now closed, the sequence to watch is the submission of the revised plan to the NEPC and its subsequent adoption, which is the point at which procurement of new capacity, renewable purchase rounds, transmission planning and storage arrangements begin to follow.

Two determinations will matter more than the headline figure. The volume ultimately fixed on adoption will set the size of the market. The regulations the ERC makes thereafter — covering how standalone storage is procured, owned and remunerated — will determine whether that market is financeable and on what terms. Neither is settled, and no timetable for the second has been announced. For the present, the prudent course is to treat the 14,500 MW as an indication of policy direction against which to position, rather than as a pipeline against which to commit capital.

Data centres, hyperscalers and export-oriented manufacturers: Direct PPA via TPA is the principal route to contracted renewable supply that can be evidenced for carbon border adjustment compliance, RE100 reporting and customer supply-chain requirements. The framework is regulatory rather than contractual: the wheeling charge, network access conditions and eligibility criteria are determined by the ERC and the utilities under the TPA Code and are not matters a buyer and seller settle between themselves. Within that framework, the commercial terms — price, term, volume and delivery profile, ownership of renewable attributes, and how the risk of a change in regulated charges is allocated over the contract life are for the parties to negotiate, subject to the conditions the final regulation imposes.

Investors and funds: Some 47.5 GW of retirements against 50.9 GW of new build creates a substantial pipeline of acquisitions, repowering projects and site reuse. Existing sites carry grid connections already in place — frequently the scarcest asset. Due diligence should test contract expiry dates against the retirement schedule.

Japanese corporations and trading houses: The PDP2026 opens three distinct entry points aligned with Japanese industrial capability: SMR technology and fuel-cycle services; CCS engineering and CO₂ transport/storage operatorship; and grid-stability equipment (STATCOM, synchronous condensers, grid-forming inverters, smart metering). The first two are long-horizon opportunities that depend on legal and institutional groundwork Thailand is still building. Grid equipment, metering and storage are addressable on a conventional commercial timetable.

6. Concluding Observation

For most businesses, the immediate consequence is a change in planning assumptions. Nothing in the draft is binding, and the figures may move before adoption. The reasonable posture is to treat the numbers as directional and to test exposure against more than one case rather than the one the Ministry prefers. With the consultation now closed, attention turns to the approval sequence and, more consequentially, to the implementing regulations that will follow it. The plan will set the volumes; the regulations will determine whether they can be built and financed.

Our Bangkok office advises on consultation strategy and submissions, power project development and contract negotiation, M&A in the Thai power sector, project and financing, and cross-border energy technology and joint venture arrangements.

Should you have any questions regarding how the PDP2026 may impact your current project development plans or cross-border investment strategies in Thailand, please contact Supasit Boonsanong at supasit.b@nagashima.com and Kobchai Nitungkorn at kobchai.n@nagashima.com.