Indonesia is a fast-growing economy, expected to become the 4^th largest in the world by 2050. To meet the growing energy demand, the government has set ambitious sustainability targets and pledged to meet net zero emissions by 2060 or earlier. The power sector will play a major role in the energy transition, but is today the country’s largest contributor to emissions from fossil fuel combustion. Over 60% of the electricity is supplied by a young fleet of coal-fired power plants whose installed capacity will meet a significant share of demand for years to come unless steps are taken now to mitigate their emissions. Gas currently represents almost 20% of electricity generation.

Indonesia has abundant natural resources and a huge potential for renewables, especially hydro, geothermal and solar PV. The national electricity plan states a target 23% share of renewables in the electricity mix by 2025 (up from 14% in 2021). To meet this target, the Electricity Supply Business Plan of the state-owned utility PLN (RUPTL 2021-2030) states it will meet the target with new hydro, geothermal and biofuel-firing capacities, and with biomass co-firing in coal plants. Implementing the plan may be challenging due to delays in the construction of these large generation projects. The plan forecasts relatively little use of solar PV due to the currently higher cost of this technology in Indonesia. Globally, however, solar PV has become increasingly competitive and its deployment can be quite rapid thanks to short construction times. This recently prompted the government to draft a new regulation promoting rooftop solar as a way to meet the 23% target.

This leads to the main research question in this study: could a higher share of solar PV fill the gap and help meet the 2025 renewables target?

The study focuses on the two main systems of Java-Bali and Sumatra, where 80% of the demand is located, and assesses their performance across a number of scenarios in terms of system behaviour, costs and emissions.

The central scenario of the study assumes that all uncommitted and unallocated capacity from the RUPTL, which includes 2.5 GW of new sources of renewable (RE), and the bioenergy portion of designated co-firing capacity would be replaced by utility-scale solar PV. This would require solar PV to reach a capacity of 17.7 GW (against 2.8 GW in the RUPTL) and an annual share in electricity of 10% (against 2% in the RUPTL) in the combined systems of Java-Bali and Sumatra in 2025. Even though such a capacity deployment looks ambitious, the scenario serves as an illustration of the potential role that increasing shares of variable renewables could play to help Indonesia reach its objective to attain a decarbonised and diversified electricity mix.

The main finding is that the existing assets in Java-Bali and Sumatra are capable of accommodating a 10% share of solar electricity by 2025 using flexibility means existing in the system. The coal and hydro plants are completely capable of delivering the needed flexibility and continue to ensure system stability and adequacy. A relatively high level of PV curtailment in Sumatra (14% yearly) is however observed, at periods of low demand and high solar infeed due to the contractual inflexibility of power purchase agreements (PPAs), as explained further. No investment in additional grids or storage capacity is required. However, this amount of variable generation requires updates to operating practices such as the appropriate forecasting and representation of these forecasts in system operation decisions, and the ability to monitor and control the operation of solar PV plants, including the ability to curtail where necessary.

On the cost side, the picture is more nuanced. Solar PV brings fuel savings from both fossil fuels (5.5-7%) and biomass (which comes at a premium) but the current regulations in Indonesia do not allow solar PV to compete in the short term when considering the total system cost. However, the authorities have options. Long-term plans for PV deployment would allow a local industry to develop and offer cheaper rates. Removal of subsidies to coal generation and the introduction of carbon pricing would further improve the business case of all renewable sources. Given the focus of the study on 2025, these longer-term initiatives are not studied in detail but could be the subject of a further study. Another aspect not included in this study is the benefits of enhanced grids and interconnections, such as the expected interconnection between Java-Bali and Sumatra in 2028. The role that increased interconnection among Indonesia’s main islands could play in the long term is addressed in IEA’s upcoming Energy Sector Roadmap to Net Zero Emissions in Indonesia.

A key barrier to accommodating variable renewables in the Indonesian power system is contractual inflexibility. Take-or-pay (ToP) obligations in PPAs between PLN and independent power producers (with guaranteed offtake obligations) and in fuel supply contracts for gas generators reduce incentives for thermal units to be flexible and affect the overall efficiency of the system. The PPA constraint is significant since the capacity of coal IPPs in Java-Bali is equal to two-thirds of the peak demand in 2025. With the assumption of a 60% guaranteed offtake each year, this significantly reduces the room in the generation mix for renewables. These contractual constraints are a barrier not only to variable renewables but also to any new renewable capacity, even dispatchable (hydro, geothermal), and lead to higher system costs. Removing these constraints, at least partially, would therefore provide room for renewables, reduce costs and help reduce emissions. To provide concrete recommendations on the contractual structures and amount of contracts to revise, more contractual data would be required.

The study does not look in detail at the role of biomass co-firing, a key contributor in PLN’s plans to meet the 23% target in 2025. It notes, however, that biomass co-firing in PLN’s existing coal plants at low blending rates (10-20% as currently considered, as these require no retrofit of the assets) may exacerbate the coal dominance in the electricity mix. Reliance on a significant share of biomass generation through co-firing in selected plants as specified in the RUPTL would require these plants to run almost flat out, while for every unit of energy from biomass, nine units from coal are forced into the system. This reduces the system flexibility and increases operating costs through interactions with other contractual inflexibilities such as gas ToP contracts. A more thorough study would be required to assess the role of biomass in Indonesia’s electricity mix.

The study also looks at the role of electrification of end-uses, like cooking and road transport, which are part of the government strategy to decarbonise the economy, reduce oil imports and improve air quality and emissions. Given the over-sized thermal capacity, increased electricity demand reduces the curtailment of solar PV (mainly in Sumatra) but also leads, in Java-Bali, to an increase in power sector emissions, supporting the need to decarbonise electricity as end-uses are electrified. Despite this, overall emissions are still reduced with the electrification of road transport, driven predominantly by efficiency gains in the move from diesel internal combustion engines to electricity for two- and three-wheelers. 

The overall conclusion is that, from a system integration perspective, Indonesia can aim for higher shares of renewables than those listed in the current plans for 2025 and beyond, especially when considering a mix of variable renewables and other dispatchable technologies. However, investment in these renewable capacities faces the risk of low-capacity factors due to the very high amount of thermal capacity in the system with inflexible contractual structures. A priority for the Indonesian power sector is to review the contractual arrangements, while respecting investors rights, and ensure that the thermal fleet is used as closely to actual technical capabilities as possible.