Investors evaluating Thailand’s energy sector face three questions: how large the opportunity is, how to enter and what are the risks to watch. The opportunity is large and getting larger. Thailand’s draft Alternative Energy Development Plan (AEDP) sets a target of 73 gigawatts of renewable energy capacity by 2037 — against an installed base of roughly 12,600 megawatts today. The gap implies approximately 3,900 megawatts of net annual additions, more than seven times the historical pace. And the Hormuz crisis has added urgency: Brent crude surged to nearly $120 a barrel in March after the Strait of Hormuz effectively closed and has mostly traded above $90 since. In response, the Thai government enacted an emergency decree authorizing THB 400 billion ($12.1 billion)^[1] in borrowing — half for cost-of-living relief, half earmarked for energy-transition measures (Royal Gazette, May 9, 2026). “Thailand remains highly vulnerable,” Finance Minister Ekniti Nitithanprapas told the IMF Spring Meetings in April, noting that oil and gas expenditure accounts for roughly 10 percent of GDP.

Source: EPPO, Energy Statistics of Thailand 2024, Table 5.2-2Y: Power Generation Classified by Fuel Type. “Renewables” combines EPPO’s “Renewable Energy” category (9.9% — solar, wind, biomass, biogas, MSW) and “Hydro Electricity” (2.7% — domestic dams). “Imported electricity” is EPPO’s “Imported” category, which includes Lao hydropower, Hongsa lignite (Lao PDR) and small interconnector volumes from Myanmar and Malaysia. Fuel oil and diesel (<0.2% combined) omitted.

Thailand’s renewable energy installed base stood at approximately 12,600 megawatts^[2] by the end of 2024, comprising bioenergy (4,543 MW), solar (3,383 MW), hydropower (3,132 MW) and wind (1,544 MW).^[3] The composition of that growth is concentrated. Under Department of Alternative Energy Development and Efficiency (DEDE)’s broader accounting — which captures behind-the-meter and private self-consumption installations that IRENA’s grid-connected dataset does not — solar has driven the overwhelming majority of capacity growth since 2018, with a sharp acceleration in behind-the-meter deployment in 2024 that IRENA’s grid-connected dataset does not fully reflect.

Solid bands: IRENA, Renewable Capacity Statistics 2025 (net AC, grid-connected; bioenergy = parent row; hydropower derived from total less other technologies). Hatched band: estimated behind-the-meter solar not captured by IRENA, derived from DEDE PV Status 2023 and IEA-PVPS Thailand 2024 (DC peak converted at approximately 1.35×). BTM gap is negligible before 2022 and estimated at approximately 4,000 MW (AC equivalent) by end-2024.

Wind, bioenergy and large hydropower have been largely static — collectively approximately 9,200 megawatts, essentially unchanged since 2018.

The scale of the gap between what has been built and what has been targeted is the context for the sections that follow. The draft AEDP 2024 sets a total target of ~73 gigawatts by 2037 — of which approximately 63 gigawatts represents domestic generation capacity, the balance being ~10 gigawatts of imported hydropower. Against a current domestic installed base of roughly 12,600 megawatts, the plan requires approximately 3,900 megawatts of net annual additions — more than seven times the historical pace. Averaged over the nine years from 2015 to 2024, annual net additions have run at approximately 200–500 megawatts per year under IRENA’s methodology, depending on the baseline window — though this headline figure masks a sharp acceleration in behind-the-meter solar deployment in 2024 that IRENA’s grid-connected dataset does not capture.

~13–15 years

Contracted revenue remaining on Adder-converted solar assets — the secondary market window

Sources: IRENA, Renewable Capacity Statistics 2025 (baseline); DEDE, EGNRET 61 presentation (Jan 2025) for AEDP target. Domestic target = 73,286 MW less 10,295 MW imported hydropower. Hydrogen (2,503 GWh) has no MW allocation in the AEDP table.

SECTION 02

How the market works

Thailand adds grid-connected renewable energy primarily through centralized procurement — government-administered programs that offer power purchase agreements at fixed tariff rates. The mechanism has evolved: an Adder scheme from 2007 offered a premium on top of the wholesale rate for ten years from COD. When this was discontinued for new solar, projects already committed were offered a conversion to a flat FiT of THB 5.66 ($0.17) per kilowatt-hour (kWh) for 25 years. By our estimate, most large ground-mounted portfolios commissioned between 2014 and 2016 converted. These assets — with approximately 13–15 years of contracted revenue remaining as of mid-2026^[4]— now constitute the addressable pool for secondary-market acquisition, as discussed in Section 4 below.

Sources: NEPC Resolution 1/2558 (Feb 2015); ERC FiT Regulation B.E. 2565 (Royal Gazette, Sep 2022); ERC Annual Report 2024; BOI Press Release 67/2569 (May 2026). Rates are nominal THB.

The current procurement regime is the 2022 Feed-in Tariff (FiT) “Big Lot,” administered by the ERC. Phase 1 awarded 4,952 MW in April 2023; Phase 2 awarded 2,145 MW in December 2024. Approximately 1,500 MW of Phase 2 remain frozen pending the next Power Development Plan (PDP). The FiT program caps foreign participation at 49 percent — a procurement-program rule addressed in Section 3 below.

Outside the FiT, at least three channels allow foreign investors to access or supply renewable energy without the FiT 49% shareholding constraint.

Corporate green tariffs (UGT). UGT1 offers large commercial and industrial users one-year access to green electricity from the Electricity Generating Authority of Thailand (EGAT)’s existing hydropower fleet, bundled with I-REC certificates. UGT1 has attracted 41 subscribers consuming hundreds of gigawatt-hours (GWh) of green electricity with the green premium set at THB 0.0375 ($0.0011) for 2026. UGT2 — the second-generation green tariff — was reported to have been launched on April 30, 2026 by MEA and PEA, making source-specific green electricity commercially available for the first time.^[5] Unlike UGT1, which draws on existing EGAT hydropower, UGT2 pairs exclusively with the solar, wind and solar-BESS generation from the FiT Big Lot pipeline, bundled with I-REC(E) certificates under 10-year retail energy service agreements. UGT2 tariffs are derived from the cost of renewable electricity procurement rather than the normal tariff-plus-premium structure of UGT1. Supply depends on FiT project completion — a dependency the EPAC flagged in mid-2024 when wind project delays threatened UGT2 readiness.^[6]

Behind-the-meter. Industrial and commercial rooftop and on-site installations operating outside the state procurement system represents a substantial and growing segment. Approximately 1.8 gigawatts of self-consumption solar capacity were installed by end-2023, and the segment has been expanding as a December 2024 ministerial regulation removed the factory license requirement for rooftop solar at any capacity.^[7] This is addressed in more depth in Section 4 below.

DPPA. The pilot, restricted to BOI-promoted data centers with IT loads of 50 megawatts or more, was approved by the NEPC in June 2024 with a 2,000-megawatt cap. The framework remains in pre-operational status: the wheeling tariff structure has not been finalized, the Third Party Access (TPA) Code is in final ERC deliberation. At the BOI Board meeting on May 6, 2026, the Board discussed steps to strengthen power readiness alongside the Ministry of Energy and the ERC, with particular attention to the eastern region where data center demand is concentrated.

Outside the FiT program, the FiT’s foreign constraint does not apply. Behind-the-meter self-consumption and equipment supply currently all operate without a foreign-shareholding ceiling, although the issue of foreign ownership limit will come up in any entry structuring decision — each to be made based on a complete business model and the activities it entails. The practical effect is a two-track market: foreign investors who want to generate and sell power into the grid face a mandatory Thai-majority structure, while those generating for their own use or supplying hardware can operate under full foreign ownership.

SECTION 04

* Draft ERC regulation (Nov 2022 consultation) would impose universal 51% Thai shareholding on all ERC licensees if adopted. † Observed models as of mid-2026; other structures may exist.

The visual above maps five of the entry models observed in the Thai market — though the boundaries between them are not always clean. What follows is an overview of who has entered through which channel and what the pattern suggests.

Japanese capital holds arguably the deepest foreign position in Thai renewables operations, spanning both the FiT system and the behind-the-meter space. Japanese energy groups hold only slightly less than 25 percent in a major Thai-listed generation company — a stake that predates the current FiT program. A wholly Japanese-owned subsidiary operates a ~22 MW rooftop installation at a tire factory in the EEC. A Franco-Japanese joint venture runs a growing behind-the-meter portfolio under a zero-capex model, with disclosed Thai projects exceeding 40 MWp. Both use the behind-the-meter pathway that sits outside the FiT system entirely.

Other non-PRC foreign capital has entered through a handful of distinct pathways, though the sample remains too small to characterize as a pattern. A Singapore-headquartered regional platform holds minority stakes in a joint venture with a Thai SET-listed developer across several ground-mounted solar parks, though the disclosed projects predate the current FiT regime. A UK-based infrastructure fund has assembled a multi-hundred-megawatt position through successive secondary acquisitions of converted-FiT solar assets — approximately 13–15 years of contracted PPA life remaining — at, according to our analysis based on SET filings, an enterprise value of approximately THB 60 million (~$1.8 million) per MWp (reflecting the remaining PPA term of the acquired portfolio; earlier-vintage assets with shorter remaining life would trade at correspondingly lower valuations). A Singaporean conglomerate holds a 49% minority in a cooling-services joint venture with a power subsidiary of Thailand’s leading power company, with secondary scope covering solar PV — structured as a minority. A Saudi state-owned developer has signed a $7 billion memorandum of understanding with PTT and EGAT for green hydrogen, though this remains at feasibility-study stage. An international development finance institution recently made its first Thai investment focused exclusively on the commercial and industrial solar sector.

PRC-headquartered manufacturers are the dominant presence in the equipment channel. Two inverter and BESS suppliers together hold an estimated 55–60% of Thailand’s inverter market. One module maker shipped 1.187 GW to Thailand in 2025. At least four Chinese module manufacturers have production or distribution footprints in the Thai market. Chinese state-owned contractors have served as EPC partners on grid-connected projects including EGAT’s floating solar and hydro-solar hybrid installations. In battery storage, three manufacturing investments in the EEC — structured as Thai-majority joint ventures — are building a domestic BESS supply chain. The scale of this hardware position is visible in procurement commitments: Thailand’s largest renewable developer has locked in seven-year master supply agreements with two PRC-headquartered manufacturers covering inverters, battery storage systems and solar modules for its entire multi-gigawatt FiT pipeline.

The gap between this hardware dominance and direct participation in generation equity is both a structural observation and, potentially, an entry opportunity — a subject we intend to address in our forthcoming Thailand Entry Playbook Part III.

Battery energy storage remains nascent. Thailand’s cumulative grid-connected BESS capacity at end-2024 was estimated at less than 100 megawatts — comprising EGAT pilot installations at transmission substations and a single utility-scale solar-BESS independent power producer project.^[9] The draft PDP calls for approximately 14,000 megawatts of energy storage by 2037, implying a total deployment over 140 times the current installed base — or approximately 1,000 megawatts per year, more than ten times the country’s entire existing storage fleet.^[10] The FiT Phase 1 solar-BESS category (994 MW) announced three years ago represents the first large-scale procurement of co-located storage; a standalone BESS procurement round has not featured in ERC or NEPC announcements to date. IRENA’s 2024 cost data show firm solar-plus-storage in high-irradiance regions at $0.054–0.082/kWh — competitive with new gas-fired baseload and projected to fall a further 30 percent by 2030. One Thai energy academic has estimated that replacing 1,000 MW of gas capacity with solar-plus-storage would displace approximately 1.6 million tons of LNG per year — roughly 16 percent of import volume.^[11]

Sources: IRENA, Renewable Capacity Statistics 2025 (historical: 4,703 MW / 9 years); ERC Annual Report 2024 p. 30 + ERC Meeting 55/2567 (active pipeline: Rd 1 4,952 + Rd 2 2,145 = ~7,100 MW / ~6-yr COD); DEDE EGNRET 61 (AEDP domestic 62,991 MW by 2037). 1,523 MW frozen by NEPC 171 (6 May 2025).

Even if every megawatt awarded under FiT Phases 1 and 2 reaches commercial operation on schedule, the annualized delivery rate of approximately 1,200 megawatts per year covers roughly 30 percent of the required pace. The remainder depends on the next PDP unlocking further FiT rounds — the program’s framework is in place but new procurement is frozen until the PDP is approved — alongside behind-the-meter expansion, the DPPA mechanism and the UGT2 channel that could not be untangled from FiT rounds and now connects corporate demand directly to new FiT-sourced generation.

~1,500 megawatts of the Phase 2 quota remain frozen pending PDP approval. No Phase 3 allocation has been announced. Further procurement is contingent on the next PDP — which has been delayed since 2024.

The opportunity is defined by numbers — 73 gigawatts targeted, 12,600 built, a sevenfold acceleration required. The entry channels are defined by regulation — a 49% cap on grid-connected generation, an open path for behind-the-meter and equipment supply and a set of parallel mechanisms still taking shape. The risks are defined by pace — whether the institutional machinery can move fast enough to convert targets into megawatts. For investors prepared to navigate the structure, the gap between ambition and execution is where the opportunity sits.

Notes