This is an extract from a recent report “Transforming Indonesia’s coal dependence into clean energy opportunities” published by IEEFA.

Indonesia is among the most coal-dependent countries globally, with coal accounting for approximately 68% (around 228 TWh) of its electricity generation. This share has increased over time. In 2015, coal contributed 56% of the energy mix, while gas and diesel accounted for 25% and 8%, respectively. Instead of transitioning away from fossil fuels, Indonesia has restructured its fossil fuel composition by reducing its reliance on gas and diesel, which have dropped to 18% and 3%, respectively, while increasing its dependence on coal. Meanwhile, despite Indonesia’s abundant solar and wind potential, these sources account for a negligible percentage, and their contribution to the grid remains minimal. As of 2024, the combined installed solar and wind capacity in the country was just 1.07 GW, and the electricity production from these technologies was only 0.27% of total electricity generation.

As of 2024, the country operates approximately 54 GW of on-grid CFPP capacity, making coal the largest source of electricity. PLN manages around 41 GW of this, with 21 GW from its own fleet and 20 GW operated by IPPs under contractual schemes. Most IPP plants are developed under buildown-operate (BOO) or build-own-operate-transfer (BOOT) arrangements, backed by long-term power purchase agreements (PPAs) that guarantee revenue regardless of dispatch levels. While PLN’s CFPPs include aging infrastructure (3.4 GW are over 30 years old, and 2.1GW are over 35 years old), many IPP-operated plants are newer and more modern. By 2030, a large share of PLN’s fleet will be over 40 years old, underscoring the critical need for strategic planning.

Repurposing legacy infrastructure to accelerate clean energy deployment

Retiring coal plants also involve social and economic transformations. Coal-fired power plants (CFPPs) and associated coal mining operations are major employers and revenue sources in many regions. Abrupt closures without adequate planning could trigger job losses, disrupt local economies, and erode public services. A just and inclusive transition requires comprehensive strategies for workforce reskilling, community support, and regional economic diversification. Former CFPP sites are among the most valuable assets that utilities own. They are already connected to the grid through permitted transmission lines, equipped with substations and switchyards, and located near water sources (which eases cooling and construction logistics).

Therefore, repurposing coal assets can be a practical solution as it offers several advantages, including reducing decommissioning costs by partially avoiding complete environmental remediation, reusing existing assets such as generators and substations, and lowering costs for greenfield builds. Repurposing coal plant sites for clean energy can be valuable, as they typically have large land areas and are already connected to the grid. Former coal sites can host solar photovoltaic (PV) installations on coal storage yards, and battery storage can be located on reclaimed or rehabilitated ash disposal areas. Generator houses can be reused to accommodate synchronous condensers and other equipment that helps maintain grid stability. Furthermore, reutilizing these assets can generate employment in renewable energy, enable coal workers to be retrained and transition into new roles, and attract new industries and investment, ensuring that communities benefit from new projects.

Other countries provide examples of repurposing their old coal assets. For instance, Canada reutilized existing coal plant infrastructure to build a 44MW solar power station in Nanticoke. Built in 1972, the Nanticoke power plant was decommissioned in 2013. Once the largest coal power station in North America, its eight generating units could provide 3,964MW of power to the southern Ontario power grid. 192,431 solar panels were installed over 158 hectares of land, and the existing transmission switch yard was used to connect to the grid.

With solar PV and BESS now cost-competitive, repurposing CFPP sites for clean energy offers one of the most practical and forward-looking solutions for Indonesia’s energy transition. Unlike retrofitting with carbon capture and storage (CCS) or co-firing, which are expensive, technically complex, and yield limited emission reductions, repurposing it with clean energy can leverage existing infrastructure and reduce costs simultaneously. Reusing these sites for solar and storage not only minimizes capital expenditure but also reduces development timelines and supports grid reliability. Transforming legacy fossil infrastructure into clean energy hubs while avoiding the escalating costs and risks associated with transitional technologies can be a successful strategy.

Indonesia’s co-firing and CCS strategy risks locking in emissions and financial burdens

Instead of considering repurposing CFPP sites for clean energy, the newly released Indonesian National Electricity Master Plan (RUKN) 2025–2060 proposes retrofitting select CFPPs with CCS, ammonia co-firing, and biomass fuel switching. While these technologies may offer incremental emission reductions, they are expensive, complex, and often incompatible with aging infrastructure. Refurbishment costs could double, as expenses include installing CCS or co-firing technology and upgrading the existing coal plant to enable continued operation. Retrofitting old plants risks locking in high costs for limited climate benefit, diverting resources from more impactful clean energy investments.

Biomass co-firing: Limited gain, high risks

Under Indonesia’s current RUKN, biomass co-firing will be gradually implemented in CFPPs at specific blending ratios. Since early 2019, PLN has piloted biomass co-firing across several CFPPs. Under the Low Emission Coal Optimization (LECO) framework, PLN has proposed expanding biomass co-firing to over 50 coal units, targeting blend rates of 10%–20%. While this strategy is purported to offer short-term emission reductions, it risks locking Indonesia into suboptimal and potentially unsustainable trajectories. Co-firing does not eliminate coal dependence; it only reduces it marginally and may delay more transformative measures such as early retirement, flexible dispatch, or complete repurposing.

Challenges also arise due to insufficient biomass supply and technical limitations related to boiler capabilities. Biomass has a lower energy content than coal. Consequently, a plant retrofitted to burn blended biomass and coal will either face lower net output or will need to burn more fuel to match its original output. For 100% biomass-fueled power plants, other technologies are required. Such plants use a different combustor-boiler design and are typically limited in size to 50 MW to 100 MW due to the practicalities of handling, storing, and processing large amounts of biomass.

Overall, the net reduction in emissions is not directly proportional to the biomass burned, as the carbon cost of growing, harvesting, transporting, chipping/processing, drying, and handling the fuel must be netted off the carbon benefit. Moreover, scaling biomass demand without robust safeguards on fuel supply can lead to unintended consequences. These include competition with food production, unsustainable land use, and increased pressure on forests, particularly in regions already facing deforestation and agricultural encroachment.

Biomass co-firing in Indonesia is projected to reduce national coal power emissions by only 1.5%–2.4%, while introducing new environmental risks and economic inefficiencies. Cost is another critical concern. Biomass co-firing in Indonesia is proving to be more complex and expensive than initially projected. In many cases, biomass, especially wood pellets and palm kernel shells, can be significantly more expensive than coal, particularly when factoring in logistics, calorific value adjustments, and supply constraints. PLN’s own procurement data shows that biomass purchasing costs for co-firing are often higher than the price paid for solar power under PPAs. 

CCS and ammonia co-firing: High cost, low scalability 

The RUKN also promotes CCS and ammonia co-firing as future mitigation strategies for CFPP emissions. While technically feasible, these approaches face substantial financial, logistical, and operational hurdles. Primarily, there are three approaches to capture carbon specifically tailored for CFPPs:

• Pre-combustion capture involves converting coal into syngas through gasification, followed by the extraction of carbon dioxide (CO₂) during the hydrogen production process. During gasification, carbon monoxide and CO₂ are generated, which are subsequently captured after passing through the shift gas reactor. The purified gas is then used as fuel for power generation, while carbon emissions are trapped and sequestered. However, this method demands significant fuel consumption due to losses incurred during gasification. Additionally, retrofitting existing facilities is unadvisable as it requires installing a new power generator capable of converting the low-carbon fuel into electricity.

• Post-combustion capture extracts CO₂ from flue gas after combustion. This process is retrofit-friendly, allowing existing equipment to continue operating, but it needs additional electricity and heat. These resources can be obtained from a new power and heat generator through cogeneration, or by harnessing energy from the existing unit and heat from the steam cycle. The internal power consumption for operating carbon capture equipment can range from 20% to 35% of the power station’s gross energy output, representing a significant energy tax on operations.

• Oxy-fuel combustion replaces air with pure oxygen during combustion, producing high concentration CO₂ for easier capture. However, it requires an air separation unit and significant modifications to the combustion system, making retrofitting complex and costly. Implementing this concept for retrofitting purposes is challenging as it involves considerable changes to the existing combustion system of the power generator, or even necessitates the installation of an entirely new unit.

Further, any CO2 captured must be disposed of. This requires compression, transportation, and injection underground for permanent storage. Not all CFPPs are located near suitable geological formations for storage, such as saline aquifers or coalbeds. Transporting captured CO₂ then adds further complexity and cost. CCS projects have consistently underperformed across sectors, with multiple projects failing or falling short of their targets. In the power sector, high profile initiatives like Petra Nova and Boundary Dam faced major setbacks, while others like Kemper never launched. Notably, NRG Energy Inc. sold its 50% stake in Petra Nova, once the world’s largest carbon capture plant, for only about USD3.6 million – less than 0.5% of the project’s roughly USD1 billion construction cost. Even purported success stories in Norway, Sleipner and Snøhvit, revealed serious geological risks and expensive interventions.

Retrofitting coal plants to run on 100% green ammonia (NH₃) is another alternative. However, ammonia co-firing has limited emissions reduction potential, fuel costs are significantly higher than coal, and technical feasibility for deployment at scale remains uncertain, especially for aging CFPP infrastructure. Shifting from conventional coal power to 20% ammonia co-firing would double fuel costs. Analysis by Bloomberg New Energy Finance (NEF) found that co-firing with high ratios of blue or green ammonia is more expensive than renewables.

According to S&P Global, the cost of green ammonia ranges from USD 800-USD 1,200/tonne, depending on electrolyzer efficiency, renewable electricity price, and scale. Both CCS and ammonia retrofits entail substantial investment costs. CCS requires significant capital expenditure, while 100% ammonia retrofitting leads to higher fuel costs. The unproven nature of these technologies adds to the risk that investments will fail to perform and, in any event, will result in significantly more expensive energy. 

Access the report here