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How hybrid PV technologies can contribute to the decarbonisation of Thailand's power system

How hybrid PV technologies can contribute to the decarbonisation of Thailand's power system cover image_A picture of Bangkok solar rooftop

In the context of COP 26, Thailand announced that it was aiming for net zero carbon emissions in 2050, with peak emissions by 2030. To achieve these targets, as outlined in the IEA’s Net Zero Emissions by 2050 Roadmap, Thailand will first need to decarbonise the power sector, which will in turn support decarbonisation of the transport and buildings sectors through electrification.

Thailand’s clean electricity transition is at the heart of the cooperation between the IEA and the Electricity Generating Authority of Thailand (EGAT), supported by the Ministry of Energy in the Kingdom of Thailand (MOEN). Work area one, for which this article summarises the first deliverable, is focused on integrating clean technologies into the modernised, future low-carbon power system.

The IEA has provided recommendations to Thailand as input to their discussions on the drafting of a new national energy plan. The IEA examined the priorities for Thai power system decarbonisation, and how hybrid technologies can contribute and provide value to the system. This article presents these findings and outlines the ways that the deployment of hybrid PV can contribute to power system decarbonisation.

While Thailand’s power generation is currently characterised by a high share of fossil fuels (81% of total electricity generation in 2021 came from gas and coal), the country has tremendous solar PV potential, both at utility scale and for rooftop PV, thanks to high irradiance and high daily solar exposure.

Power generation mix in Thailand, 2020

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Solar PV is a low-cost source of clean electricity with high potential for decarbonising power systems. It is, however, a variable resource, as generation fluctuates with the weather.

In systems with growing shares of variable renewable energy (VRE) sources, power system flexibility plays an increasing role, as can be seen in the IEA NZE Scenario, in which global electricity system flexibility quadruples by 2030.

As flexibility needs can differ depending on the timescale, situation and share of VRE, the IEA has developed a framework of six phases to assist policy makers in identifying the needs related to system integration of VRE.

Main flexibility priorities by renewable integration phase

Phase

Phase 1

Phase 2

Phase 3

Phase 4

Phase 5

Phase 6

Main priority

Typically no system flexibility issues

Short-term flexibility

Short-term and medium-term flexibility

Ultra-short-term, medium-term and long-term flexibility

Long-term flexibility and very long-term flexibility

Very long-term flexibility

The classification into phases is key in order to identify the flexibility needs of the Thai power system both now and as the system evolves towards further decarbonisation. Currently, the Thai power system is in Phase 1, transitioning towards Phase 2, which means that system operators are starting to notice VRE generation. In Phase 2, short-term flexibility needs will be the most crucial to address. Increased medium-term flexibility will also be key as the system moves towards higher shares of VRE, as well as in Phase 3.


Planning for increased power system flexibility should happen at the system level. Indeed, flexibility can be provided by several different tools and at different timescales. It is therefore crucial to assess system needs in detail in order to ensure the deployment of the right tools. Three main building blocks of power system flexibility exist:

  • technical flexibility, which can be provided by power plants, grids or storage
  • contractual flexibility, which is related to the curtailment conditions and potential limitations from take-or-pay conditions, to name a few
  • modern operational practices such as forecasting requirements, or the sizing of operating reserves.

These building blocks were assessed in the Thai context with the results showing that the Thai power system had significant technical flexibility. To ensure adequate and cost-efficient power system decarbonisation, leveraging this existing system flexibility is important. Doing so will avoid additional deployment of flexibility tools, while ensuring that the resources are used optimally. However, while the Thai power system has significant latent flexibility, accessing it is constrained by contractual structures. The first priority in Thailand’s power system decarbonisation is therefore enabling the use of existing asset flexibility by adapting these structures, for example by minimising minimum-take obligations, or by re-negotiating take-or-pay requirements in fuel supply contracts.

Adapting operational practices to a system with higher shares of VRE is a second measure to consider. In the case of Thailand, from the technical standpoint, the most constrained dimension of power plants is the minimum stable level (MSL). Lower MSLs of thermal fleets can enable the system to better accommodate to the daily variations in net demand.


Integrating growing shares of VRE into power systems requires a shift in the way the system is operated, as the determining factor for operation becomes the net load, meaning the difference between the system load and the output from VRE generators. When weather conditions change, there can be strong ramps in net load as the output of VRE generators changes. Each technology’s benefits and drawbacks must be considered when creating decarbonised power systems. It is also important to consider how the interplay between these different technologies can bring additional value to the system.

We assess here the ways that selected clean technology options – solar PV, battery energy storage systems (BESS), hydropower and hybrid PV – add value to power system operations, and how they can be utilised in an optimal way.

Variable renewable energy sources such as solar PV can provide flexibility if their operation plan allows it – and, when they are viewed over a large region, their aggregate profile is less variable. For example, a study that considered several solar PV plants located over a radius of 100 km showed that the production variability was lower than when looking at each single plant’s output. Similarly, the ramp rates of solar PV production were de-correlated in distances over three km in timescales under five minutes.

While the installation of solar PV on water surfaces is a relatively new practice, the interest in it has increased in recent years. The main advantages of floating solar PV are that it avoids competing for land use, it increases the yield provided due to the cooling effect of the water, and it has the potential to reduce both water evaporation and water temperatures. However, the installation of solar PV on water surfaces is more complex than on land. Since the panel anchoring cannot be subjected to high variations in water levels, currents or waves, it could introduce additional locational and operational complexities.

BESS offer fast and accurate response times to dispatch signals from system operators. Their modularity enables a tailored deployment, and they are able to provide multiple power system services such as energy and ancillary services, which contribute to the fulfilment of reserve requirements and reduce congestion.

Hydropower is the largest renewable electricity source globally. It can offer a cost-effective solution by contributing to flexibility, energy storage and ancillary services. It can also provide several different flexibility timescales and will be especially relevant for power systems in Phase 3 or higher of VRE integration, in which the ability of hydropower to dispatch and quickly ramp up can address changes in net load.


When taking a system-wide approach, one has to consider not individual technologies, but their interaction in a power system which can create benefits beyond those coming from each technology alone. These complementarities can be strongly beneficial for the power system in that they may compensate for the constraints produced by individual technologies while maximising the value they provide.

A system with a portfolio that has a diverse set of technologies can take advantage of such complementarities and minimise the need for further flexibility. In this manner, a system-level perspective is necessary to discover and account for these benefits that arise from interactions between different technologies when defining the needs for flexibility.

Hydropower and BESS both present dispatchability and storage advantages that are particularly interesting when combined with solar PV. Batteries can interact with solar PV by storing excess electricity generation in times of high availability and low demand, and re-inject that electricity at times when demand exceeds solar PV generation. Similarly, while solar PV is non-dispatchable and presents seasonal effects, hydropower can be dispatched to compensate for the generating pattern of solar PV, while at the same time having a seasonal pattern complementary to that of solar PV.

Indeed, synergies exist between solar PV and hydropower at different timescales. At hourly and daily scale, hydropower generation can be shifted to times of low solar PV availability. This also enables optimisation of the use of the water resource – which acts as a short-term storage – and minimises solar PV curtailment. The IEA case study of Indonesia’s Cirata hydropower plant, for example, showed that adding solar PV to the system enabled a shift to hydro generation towards the evening, thereby addressing the peak in demand occurring at that time. A hydropower plant’s capacity to ramp up or down to compensate for the variation in solar PV generation is an additional advantage, but in very short timescales it might be constrained by the hydropower plants’ discharge restrictions.

Second, solar PV and hydropower present strong seasonal complementarity, especially in countries with dry and wet seasons. Indeed, the availability of these resources is asynchronous in such countries. In the wet season, when solar PV generation is lower, there is more water inflow, hence more potential to generate electricity from hydropower plants and vice versa. In the dry season, the increased availability of solar PV can reduce the pressure on the water resource, making more water available for other uses such as irrigation.


A common misconception is that in order to harness these complementarities between technologies, a hybrid plant setup is needed.

Hybrid generation technologies combine different energy generation, storage and conversion technologies. The way the different constituents are combined, both in terms of location and operation, will define their degree of hybridisation and how they are perceived by system operators. It is therefore important to distinguish between the levels of hybridisation, which we do following the taxonomy of the Renewable Energy Laboratory (NREL) at the United States Department of Energy:

  • Co-location, where a geographical link exists between constituents (through a shared point of interconnection for example), but where the operation of the different plants is independent. From the perspective of grid operation, co-located resources do not differ from two individual technologies as they are controlled individually.
  • Virtual power plants, which do not have a geographical link, but an operational one, which ensures a coordinated control of the technologies, taking advantage of their synergies.
  • Full hybridisation, where both a locational and an operational link exist, and components are often shared. Here, the technologies are integrated fully so that at the point of interconnection, the hybrid resource is treated as a single resource and from a system operator’s perspective, the constituents are therefore seen as a single plant.

Leveraging the complementarities between technologies is, however, possible as soon as the different technologies are integrated into the same power system.

To illustrate this, we analysed the effect of adding 5 GW of solar PV to the power system on the hydropower generation profile using the production model from the IEA Thailand Power System Flexibility Study. Three scenarios were considered, each at horizon 2030 and each considering the accelerated deployment of VRE based on targets from the ASEAN Interconnection Masterplan Study (AIMS-III) project (15% share):

  • a base case 1
  • the “Additional Solar Scenario” in which the 5 GW of solar PV are added at an unrestricted location close to the load centre (in this case, the Metropolitan Bangkok (MAC) region)
  • the “Additional Solar, Co-located Scenario” in which the 5 GW of solar PV are co-located with hydropower reservoirs in the North-eastern (NEC) and Northern (NAC) regions, and the output of the co-located plants cannot exceed the capacity of the hydropower plants (assuming shared infrastructure).

By comparing the base case with the two “additional solar” cases, it is apparent that the addition of solar PV to the power system causes the hydropower profile to adjust its daily generation profile to accommodate the production profile of the solar resource. Hence, in both “additional solar” cases, on average there is higher hydropower generation in the night hours than in the base case – while during the day, hydropower generation is lower.

This demonstrates that hydropower provides intra-daily flexibility to the system as the share of solar PV increases independently from co-locating the two resources.

Average hydropower generation between 3pm and 5pm in Thailand in the three different scenarios, 2030

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Average hydropower generation over a day in Thailand in the three different scenarios, 2030

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When planning to deploy hybrid technologies, it is therefore important to assess the additional advantages these technologies can bring, beyond those produced by technology complementarity, both from system level and asset owner perspectives.

Hybridising technologies provide additional benefits exclusive to the hybrid setup that will depend on the level of hybridisation of these technologies. These benefits will sometimes be relevant from the system perspective, and other times will be visible only to the asset owner – a difference in perspective that is important to take into account in power system planning in order to ensure that the benefits created for asset owners are also reflected at system level.

When co-locating technologies, a physical link is established between them, and they are constructed in the same geographical location. The main benefit of this proximity is the possibility of sharing infrastructure, which will reduce the transmission interconnection costs and increase the use of the transmission network. In addition, in certain cases, co-location requires less land for deploying such technologies. For example, in the case of a wind-solar PV hybrid, less land is needed than when the two plants are located independently because the solar PV panels can be installed between the wind turbines. Lastly, in cases in which the hybrid constituents are developed and constructed at the same time, the upfront costs related to permitting, site acquisition and engineering can be minimised compared to those involved when developing several independent plants.

One advantage of building a virtual power plant (where the hybridisation is only operational, without a locational link), is the ability to optimally site the different power plants that constitute it. Furthermore, the coordinated control of the technologies increases their operational value – at least from the perspective of the asset owner. Indeed, the diversity and complementarity of generation sources provides the ability to control and optimise the virtual power plant’s output so as to provide high revenue services to capacity markets and ancillary service markets. These benefits to the asset owner may not, however, be perceived as benefits from the system perspective. Hence, system operators should ensure that the benefits earned by a virtual power plant are not created by a transfer of value from other assets.

In a fully hybridised setup, in addition to the benefits outlined above for co-located and virtual power plants, further advantages exist.

In the case of BESS coupled with solar PV at direct current level, its hybridisation can improve inverter utilisation. Sharing an inverter enables the hybrid setup to recover otherwise lost generation. This happens, for example, by avoiding the losses of passing through several inverters. In addition, this type of setup results in reductions in the amount of battery charging from the grid, by replacing it with electricity from the onsite solar PV plant, thereby reducing costs for the plant operator and improving the efficiency as there are reduced transmission losses and charges. In this case as well, differentiating between the benefits at plant level and system level is important, and an assessment of the value for the system is needed to ensure the hybrid setup is the most optimal solution from the grid operation perspective.

Finally, the fact that the two technologies are located closely and controlled together can reduce response times, thereby enabling faster reactions to system signals. 

Advantages obtained by technology

Benefit

Obtained by

Avoided land use in PV sitting

Floating PV

Shared infrastructure

Hybrid PV with physical interconnection

Increased inverter utilisation

Full hybridisation

Increased plant utilisation (from asset owner perspective)

Full hybridisation

Upfront cost optimisation (shared permitting, site acquisition, etc.)

Hybrid PV with physical interconnection (if the two technologies are developed together)

Increased use of transmission interconnection and network

Hybrid PV with physical interconnection

Leveraging complementarities between technologies

System-level control (from grid operator perspective)

Virtual power plant or fully hybridised plant (from asset owner perspective)

Faster response (flexibility)

Full hybridisation

Source: IEA compilation based on Murphy et.al. (2021), A taxonomy of systems that combine utility-scale renewable energy and energy storage technologies and Lee et.al. (2020), Hybrid floating solar photovoltaics-hydropower systems: Benefits and global assessment of technical potential.


While hybridisation has many advantages, it also adds locational and operational constraints, as well as a loss of visibility to system operators. These disadvantages need to be assessed and weighed against the benefits in order to ensure that the plant’s construction provides net benefits to the system.

First, in co-located or fully hybridised setups, the developer constructs multiple installations (e.g. solar, wind, battery or hydropower) in the same location. The chosen location, however, may not be ideal for any one of them, which would introduce the need for a compromise when co-optimising the location. This could reduce the potential of individual constituent technologies to provide system services such as non-wire alternatives, or reduce the potential yield.

For example, by installing solar PV and BESS in a hybrid setup, the location decision will be the result of a compromise between the optimum solar resource and the potential of the battery to relieve congestion. It is possible that installing the two resources in different locations could produce more solar PV electricity (due to higher solar irradiation at that location for example), while allowing the battery to serve as a non-wire alternative and thus reduce congestion.

This trade-off is particularly clear when considering hybrid hydropower projects. As the locations suitable for hydropower plants are extremely limited, from the perspective of solar PV siting, the joint locations are often suboptimal.

The decision in favour of hybridisation should therefore be based on verification that the system-level costs of the locational drawbacks are offset by the advantages of the hybridisation. Where in certain cases, the cost-benefit analysis might be positive for the plant operator, it is crucial to check that the setup makes sense from the system-level perspective.

Secondly, hybridisation can also add operational constraints, which result from the shared infrastructure or the operational linkage. In terms of infrastructure, and in the case of a retrofit addition of solar PV to existing plants, a constraint may exist in terms of the capacity of the connection point (described below). Furthermore, in the hybrid PV and BESS setup, sharing an inverter, while bringing some advantages as outlined above, limits the output in times of high generation. In the case of hydropower, the operation range of the plant could limit the full dispatchability of the hybrid system. Hydropower ramping for short-term flexibility, for example, could be constrained by the allowed volumes of water discharge downstream.

Coming back to our modelled example, and looking at the differences between the two “additional solar” scenarios, one can see that there are slight differences in the way the hydropower generation is adjusting over time. In the co-located scenario, to take into account the shared infrastructure of the hydropower/floating solar plant and the constraint on the PV generation due to the reservoir’s location, two additional constraints were introduced into the model. Firstly, the scenario is modelled assuming the use of common transmission and distribution equipment and is therefore limited to the capacity of the existing hydropower plant (5.34 GW) at which they are located. Secondly, there is limited transmission capacity between the hydropower plant that is in the northern region of Thailand and the main load centres located in the centre of the country. These two constraints lead to slight differences between the two “additional solar” cases. Indeed, the adjustment of the hydropower profile to solar PV availability is stronger in the co-located scenario, as the capacity of the shared infrastructure limits the total output at the site. The fact that the hydropower resource is increasingly used to balance local congestion instead of being controlled at system level reduces the cost-efficiency of the system.

Lastly, in full hybrid or virtual power plant setups, a trade-off is the loss of visibility from the system operator’s perspective. Indeed, the fact that the hybrid technologies’ constituents are controlled together renders their individual behaviours invisible to grid operators, who then rely on plant operators to ensure operations are managed in a system-optimum way. Providing incentives and regulations to plant operators to ensure that operations are system-friendly can address this drawback. 


To decarbonise its power system, Thailand will have to deploy considerable amounts of solar PV capacity, which will in turn require an increase in the flexibility of the system. Flexibility can be obtained not only from changes in operational procedures but also from diverse assets as well as through contractual arrangements – and it is indeed important to assess these options and determine the best, most cost-efficient and secure, portfolio of assets. In the case of Thailand, the highest- and lowest-cost potential resides in tackling contractual inflexibilities through fuel supply contracts and power purchase agreements. With accelerating VRE deployment, hydropower plants and batteries are strong flexibility assets, which bring value to the system by providing short- to long-term flexibility. These technologies further present interesting synergies with solar PV at the hourly, daily and seasonal scale, which, when maximised at system level, can effectively improve system operation and minimise additional flexibility needs. Hybridising them with PV can bring additional value by reducing grid connection and upfront costs, enhancing inverter utilisation and providing faster response possibilities. The hybrid setup, however, also comes with trade-offs, such as the necessity to compromise when siting the plants. Hence, each deployment of solar PV has to be accompanied by a careful comparison of costs with benefits, to ensure that the advantages of the hybridisation surpass the potential additional costs.

References
  1. The base case considers the Thailand power system as modelled in the Thailand Power System Flexibility Study under the "Base 2030 ASEAN RE Scenario”. Under this scenario, the system was modelled with 600 TWh of annual demand and 45 GW of peak demand. The generation mix included 18.8 GW of solar PV capacity and 6 GW of wind capacity to reach a 15% share in VRE generation.