Executive summary Decarbonising Thailand’s power system is crucial to its net zero strategy During the 26th Conference of the Parties in 2021, Thailand committed to reach carbon neutrality by 2050, and net zero greenhouse gas emissions by 2065. The country’s 2022 long-term low greenhouse gas emission development strategy (LTLEDS) focuses on the energy sector, which is the highest-emitting sector with 69% of the total GHG emissions in 2018. The power sector is key to the strategy, since electricity currently accounts for 35% of energy sector carbon emissions, and further electrification will be essential for reducing industry, transport and buildings sector emissions. In 2021, 66% of Thailand’s generation mix was covered by natural gas and 17% by coal, while low-carbon sources provided only 12%. A rapid scale-up of clean generation will therefore be needed to align power sector development with Thailand’s climate commitments.

Thailand’s climate policy ambitions will require updates to the PDP The power sector in Thailand is planned centrally through the Power Development Plan (PDP). The current version of this plan, PDP 2018 Revision 1 (hereafter “PDP 2018”), was published in 2020, before Thailand updated its climate objectives, and is not yet aligned with the new emissions targets. Based on the generation buildout in PDP 2018 emissions would exceed the targets by 44% in 2030 and 80% in 2037.

The main reasons for emissions surpassing the targets are expansion of coal and gas capacity – 16 gigawatts (GW) total – and insufficient clean electricity expansion – 18.8 GW of renewables – to drive the required reductions. Based on the current PDP and the EGAT’s demand projections from 2022, power sector carbon emissions would rise 12% above 2021 levels by 2037. These demand projections integrate energy efficiency measures planned by the Thai government and the use of power for cooling and transportation, and result in a 4% average annual growth rate from 2021 to 2037. The Thai government has announced a planned update to the PDP, in the frame of the broader new National Energy Plan. To support this update, we have modelled the Thailand power system to 2037 and assessed the potential to meet the new climate targets by increasing the deployment of solar PV and wind (VRE Plus scenario) in comparison with the PDP 2018 (Base scenario). We also assess the flexibility required to integrate this additional variable renewable energy VRE) generation.

Thailand’s power sector is structured as an enhanced single-buyer model Several stakeholders are involved in Thailand’s power sector, including the Ministry of Energy, the Energy Regulatory Commission (ERC), the governmentowned utility EGAT, two distribution companies and independent power producers (IPPs). The Ministry of Energy’s role is formulating policy and strategy to ensure energy security and affordability, and sustainable energy in the country. The ministry is split into four departments, of which the Department of Alternative Energy Development and Efficiency and the Energy Policy and Planning Office. that are, together with EGAT and the ERC, responsible for preparing the PDP. The ERC regulates energy industry operations and promotes the use of renewable energy and energy efficiency. EGAT, as a vertically integrated utility in Thailand’s enhanced single-buyer model, has the responsibility to perform central planning of the Thailand power system. Its role is to allow for adequate generation, transmission and flexibility measures to meet its growing demand. It owns 34.5% of the power system’s total generation capacity. The authority further acts as the single buyer of electricity from IPPs, small power producers (SPPs) and neighbouring countries.

IPPs and SPPs are both connected to the transmission network. The difference between the two is the size, as IPPs have a capacity greater than 90 MW and SPPs a capacity between 10 MW and 90 MW. Distributed generators are called very small power producers (VSPPs). Two distribution utilities exist in Thailand, the MEA and the PEA. EGAT sells wholesale electricity to them, as well as to a few direct industrial customers and utilities in neighbouring countries. The MEA then supplies consumers in Bangkok and the metropolitan area, while the PEA supplies the rest of the country.

Most of Thailand’s power generation is fossil fuel based By December 2022, the installed generation capacity in Thailand was of 49 GW, of which 72% was fossil fuel based, with a majority (59% of the total capacity) being gas power plants. EGAT owns 16 GW (35%) of that capacity, while IPPs account for 33% and SPPs for 20%. The rest (12%) is made up by imports. Looking at the domestic electricity generation mix in 2021, natural gas took the main share with 66%, followed by coal (17%), bioenergy (8%) and hydro (2%). Wind and solar power each contributed to 2% of the total generation. Thailand, however, also imports hydropower and coal power from its neighbours Lao PDR and Malaysia. When including these imports in the mix, the hydropower share increases to 13% of the total and the coal power share to 22%, and the natural gas share decreases to 53%.

Thailand is also involved in sub-regional multilateral trading efforts that aim to integrate ASEAN member states into a common ASEAN power grid to improve energy security, and increase the shares of variable renewables the system can integrate. The country acts as wheeling country in the Lao PDR-ThailandMalaysia-Singapore Power Integration project (LTMS-PIP), under which up to 100 MW of hydro electricity are exported by Lao PDR to Singapore since June 2022, via Thailand and Malaysia. It also participates in the Greater Mekong Subregion integration effort.

Thailand can build upon its variable renewable energy resources to decarbonise its power mix One key pillar of Thailand’s power system decarbonisation is its solar PV potential. Indeed, the country has high solar irradiance, especially in the northeast and southern part of the country, and high daily solar exposure. The country has high potential for utility-scale solar PV deployment, and previous IEA analysis showed that the country also has strong potential for rooftop solar. It was demonstrated that with 10% of the available estimated rooftop surface used for distributed PV, the capacity hosted would be larger than the system’s current peak demand.

In addition, the country can develop its wind power capacity, for which the highest potential is located in the north-eastern region of the country. However, as there is a discordance between the location of the wind and solar PV resource and the demand centres that are located towards the centre of the country, the transmission of the clean power towards demand centres will have to be considered, as our analysis will further highlight in the next chapter.

Demand is represented at a regional level, with an hourly resolution and is based upon updated projections from the Energy Policy and Planning Office (EPPO) that have been prepared for the forthcoming update to their PDP. This, importantly, includes updated projections for EVs and energy efficiency.

Ambitious emissions targets require a suite of flexibility measures to ensure efficiency and reliability As the emissions targets for Thailand further tighten towards 2037, two key challenges arise which need to be addressed by system planners and system operators alike. First, the tightening emissions targets for later years begins to limit the system flexibility that one can readily derive from thermal plants. Additionally, uncommitted thermal plants which were planned for commissioning during the period 2030-2037 are removed. These plants were meant to account for both energy and peak capacity requirements, which increase by 3.5% and 4.1% per year respectively. This means that both the energy and capacity from these plants need to be replaced by clean energy alternatives.

A good indication of system flexibility needs can be provided by looking at a generation stack of the system during periods of system stress (e.g. periods of peak or minimum net demand). On analysis of the modelled system under the VRE Plus scenario, one sees that despite a growing installed capacity of VRE, this capacity (which is 75% solar PV) makes very little contribution towards peak periods, due to the combination of low wind generation during this period and an evening peak demand during which solar PV production makes little to no contribution. This results in a system that has insufficient capacity to meet peak demand requirements during certain periods without additional flexibility, especially from storage or smart charging EVs which help to shift demand to better match VRE production.

During periods of lower demand, and especially minimum demand around weekends and holidays, the growing imbalance between supply and demand becomes more evident as large amounts of both solar PV and wind production need to be curtailed to ensure the balance of supply and demand. Although this already occurs in 2030, this becomes much more evident in 2037 as there are many periods where VRE production exceeds demand (i.e. negative net demand). At the same time, the system must also accommodate must-run generation and the technical constraints of other dispatchable generation. Therefore, there is

need to either curtail this excess generation or shift demand to better align with VRE production. Here again, flexibility from storage and smart charging EVs can help to reduce curtailment and therefore the efficiency of deployed VRE generation while also reducing the need for thermal generation during the evening peak. Increased power plant flexibility also helps to make more efficient use of remaining thermal plants through lower minimum stable levels that allow for these plants to reduce their output to lower levels while remaining online in order to provide generation during periods of lower VRE production.

Digitalisation is crucial when deploying EVs in a grid-friendly way, as managed charging can be put in place only when deploying smart charging technologies, coupled with the right pricing signals. Digitalisation plays an important role in unlocking additional flexibility in the system, at transmission and distribution levels. It may allow for new services to be offered to the power system, especially through the connection, control and aggregation of the demand side. For example, distributed demand-side assets could provide fast-frequency response, and distributed batteries or EVs could provide inertial response. When enabled through digital technologies, connected, distributed energy resources become visible and can be monitored by operators, controlled remotely and aggregated to provide system services.

Indeed, to take full advantage of batteries, it is important for policy makers to make sure owners of batteries receive price signals that reward grid-friendly behaviour, such as charging in times of excess VRE generation. Furthermore, the assets should be visible to system operators and aggregation allowed to make the most of the services provided. Policy makers should hence look into updating operational practices and lowering regulatory barriers to facilitate the use of storage.

Modelling scenarios of increased VRE penetration The model considers two main scenarios (“Base” and “VRE Plus”) based on three different modelling years (2025, 2030 and 2037), in addition to the validation of the model against historical generation and demand values for 2021. The first of the two main scenarios is the “Base” case, which considers the development of the capacity mix as per the PDP2018 revision 1 (“PDP2018”), and represents a business-as-usual reference case for the development of the Thailand power system Meanwhile, the second scenario, “VRE Plus”, considers an alternative capacity mix that considers the deployment of wind, solar PV and the necessary flexibility options (specifically storage and inter-regional transmission) in order to meet the emission targets for the Thailand power sector.

Source:IEA