Indonesia Power Sector Finance Dashboard
The Indonesia Power Sector Finance Dashboard showcases recent trend analysis of investments in the country’s renewable energy (RE) vs fossil fuel (FF) power plants. The Dashboard includes a deep dive into investments that flow through state-owned electricity firm PLN, to ensure transparency and accessibility of investment data and to show how those investments particularly impact Indonesia’s energy market and energy transition journey.
Snapshot of Indonesia’s power-sector finance: Fossil Fuel vs Renewable Energy
Takeaways
• Indonesia still lacks funding in its power sector to reach 2030 climate targets.
• Investment in the Indonesia power sector is highly driven by private financiers, particularly for FF.
• The source of FF financing in Indonesia is highly dominated by private international finance; China and South Korea are the leading sources.
• For RE, private finance is growing, but public finance remains sizeable (16%).
• The majority of RE investment is still targeted to baseload type power plants; more funding is needed across the RE power generation and delivery supply chain.
Continue reading to dive into the details of power sector financing in Indonesia.
Unreported FF investment and additional categories of RE infrastructure
As it generally takes three years to complete construction of a coal-fired power plant (CFPP), the reported investments in coal (2019-2021) were cross-checked against data of CFPPs that began operating between 2022 and 2023. The result suggests that 1,500MW of CFPPs were not captured in the data of reported coal investments.
Upon estimating the project costs of CFPPs not captured in the 2019-2021 investment data, the real amount of investment in coal was likely larger, with around $2.8 bn of unreported investment.
Two categories of supporting infrastructure investments were not captured in the reported investments due to a lack of data. These are multipurpose investments (result-based lending, state capital participation, and green credit portfolio) and investments in Transmission & Distribution.
Investments in RE were mostly derived from international sources (58%) and concentrated in baseload RE (e.g. hydro and geothermal) due to generally mature technologies and risk profiles.
Lack of more diverse RE investments can be attributed to uncompetitive tariffs, high local content requirements, and preferential policies for coal.
In terms of financing instrument, 79% of geothermal investments were through concessional loans and grants, indicating that public funds were needed to accommodate investment risks.
For hydropower, only 13% were from grants and concessional loans, with the rest being equity investment and market-rate loans.
A local content requirement that clashed with some international DFIs’ procurement policies might be a major factor that deterred the DFI’s investment. Moreover, most concessional loans require sovereign guarantees, which can only be provided for SOEs.
For FF, investment relied least on concessional finance. Coal investment was dominated by market-rate loan, while financing for gas plants was derived mainly from unspecified sources.
After factoring in the unreported coal investments and the additional investment categories (Multipurpose and T&D), fossil fuels retained the largest share of investment (57%).
South Korea contributed the largest amount of FF investment ($6.5bn), followed by China ($2.3 bn). Investments from the two countries might decrease in the coming years considering recent climate pledges that China and South Korea have made.
Deep Dive Analysis of funding flow through PLN
For on-grid power investments, the independent power producers (IPP) received the largest share with $4.6 bn in RE (~22% of total) and $4 bn in fossil (~19% of total), while PLN received $1.2 bn (~6% of total) in RE, and none in FF.
IPP received the larger share of coal investment at around $3.7bn, mostly in market-rate loans. Meanwhile for gas, IPP received $0.4 bn, with a larger share of $5 bn allocated for captive (solely for the 4.8GW CCGT Power Plant in Batubara Regency, North Sumatra, with financing modality not specified).
With $9.4 bn or 84% of total FF investment, international private FIs were by far the largest contributor. Meanwhile, domestic private FIs contributed $1bn, mostly to IPP coal-fired power plants (Jawa-9 and Jawa-10 each at 1 GW capacity).
Smaller contributions from public FIs were also reported, namely from ADB and IFC to gas, and from Korea and China public banks to coal.
IPPs received the largest share of RE financing, with $3.6bn from private FIs and $0.9bn from public FIs.
Meanwhile, PLN received roughly equal amounts of RE financing from public FIs ($0.7bn) and private FIs ($0.5bn).
Instruments for IPPs’ RE financing vary by output.
Within the more prominent output category of baseload RE, hydropower received a larger share of equity ($2.0 bn) followed by market-rate loan ($1.4 bn), while geothermal received a larger share of concessional loan ($0.6 bn) followed by equity ($0.3 bn).
Coal plants accounted for both the largest share of annual operating costs (~45%) and of annual production (65%).
Gas and diesel also incurred significant costs (~35% and ~15% respectively) but contributed far less to annual production (~20% and ~6% respectively), indicating higher costs of production.
Except for hydro and solar, fuel contributes the most to operational costs per unit production.
The highest operational cost was incurred by diesel (IDR 2.2k/kWh), followed by gas (IDR 1.4k/kWh) and solar (IDR 1.3k/kWh).
For coal, we can see the effect of the government’s policy on Domestic Market Obligation (DMO), which lowers the price for domestic buyers (as compared to the export market price) and also its eventual operational cost.
If we adjust the price of coal using the export market price, its operational cost doubled (from IDR 0,5k/kWh to IDR 1.0/kWh).
While other types of power plants perform relatively close to their benchmark, PLN-owned solar plants have a far below average capacity factor relative to its benchmark.
Capacity factor refers to the ratio of a power plant’s actual output over a period to its maximum potential output/installed capacity.
This contributes to Solar plants’ lower production and higher operational cost per unit of production.
The below-average capacity factor of PLN solar PV could be attributed to:
• Curtailment: Not all electricity production can be absorbed by the grid.
• Low efficiency of operations/technology used that causes low production of solar PV.
More data on the above root causes is needed to close the gap between the capacity factor of PLN solar PV with its regional benchmark. This will significantly reduce its operational costs (as modeled in the graph).
Indonesia Power Sector Finance Dashboard
Needs, Flows, Gaps, Opportunities, and Actions
For Indonesia to achieve its stated 2030 climate targets, there is currently a substantial gap between the annual $9.1 bn RE finance needed and the $2.2 bn per year currently invested.
With total investment in FF power plants almost twice the size of that in RE power plants, there is a tremendous opportunity to rethink and shift those investment flows, especially from international private FIs as the largest contributor.
By leveraging the data available here, and in our report, policy and investment can be optimized to build a more resilient, secure, equitable, and low-carbon future for Indonesia.
