Indonesia Power Sector Finance Dashboard (2019-2023)
Indonesia Power Sector Finance Dashboard is the first-of-its-kind investment tracker showcasing the latest and most comprehensive trend analysis of investments in renewable energy (RE) vs fossil fuel (FF) power plants.
This tracker also includes a deep dive into investments that flow through state-owned electricity firm PLN to show how those investments particularly impact Indonesia’s energy market and energy transition journey.
Snapshot of Indonesia’s power sector finance (2019-2023)
Indonesia’s power sector requires a total investment of $246 bn—around $19 bn annually through 2030—to achieve its climate targets.
Takeaways
- Indonesia still lacked funding in its power sector to reach 2030 climate targets.
- Investment in the Indonesia power sector was highly driven by private financiers, particularly for FF.
- The source of FF financing in Indonesia was highly dominated by private international finance.
- Private financing remained dominant for RE, accounting for 60% of total investment, while public sources contributed the rest.
- The majority of RE investment was still targeted to baseload type power plants; more funding is needed across different types of RE power generation.
Continue reading to dive into the details of power sector financing in Indonesia.
Unreported FF investment and additional categories of RE infrastructure
The Unreported CFPP investments during the 2019 – 2023 period were estimated by:
- Collecting data of CFPP capacity with commercial operation date (COD) between 2022 – 2025, with the assumption that finance flow would occur 3 years before COD, based on the average CFPP construction period of three years.
- Gathering data on the capacity (in MW) of CFPPs that had financial close within the period (2019-2023) but were not reported in financial database sources.
- Calculating the unreported finance flow (investment cost) by multiplying the capacity data in (1) and (2) with MEMR’s data on CFPP project construction costs per megawatt.
The result suggests that 6,765 MW of CFPPs were not captured in the data of reported coal investments.
By estimating the project costs of coal-fired power plants (CFPPs) that were not included in the investment data between 2019 and 2023, it’s inferred that the actual investment in coal was likely larger, amounting to approximately $10.63 billion 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 domestic sources (55%) 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 PLN’s preference for Baseload, i.e. Hydro and Geothermal.
In terms of financing instrument, 64% of geothermal investments were through concessional loans and grants, indicating that public funds were needed to accommodate investment risks.
For hydropower, only 22% 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 DFI’s 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.
Investment in Variable RE (Solar and Wind) started to grow since 2021. This is in line with a more favorable RE procurements policy issued in 2022.
For FF, investment relied least on concessional finance. Coal investment was dominated by market-rate loans, while financing for gas plants was derived mainly from equity.
The reported data indicated that China, Multilateral DFIs, and South Korea were the leading investors in Indonesia’s power sector. Multilateral DFIs’ investment was concentrated on RE and T&D, while China and South Korea demonstrated significant FF portfolio.
Following their 2021 pledges, China and South Korea appeared to have halted their investment in FF power plants. In 2022-2023, South Korean companies committed to divest from Cirebon-1 CFPP ownership as part of its early retirement plan (as of 2025, the transaction of divestment has not occurred). However, investments from China on coal power for industrial purposes were estimated to increase in 2021-2023, primarily for captive use in nickel mining and smelters in Eastern Indonesia (e.g. Morowali, Weda Bay).
Deep Dive Analysis of funding flow through PLN
For on-grid power investments, the independent power producers (IPP) received the largest share with $5.0 bn in RE (13% of total) and $5.8 bn in FF (15% of total). While PLN received $2.1 bn (6% of total) in RE, and $1.7 bn (5% of total) in FF.
Captive Power investments (43% of total) presents a challenge as it mostly skews toward fossil fuels power generation.
Indonesia’s “down-streaming” policy*, implemented in 2020, is fueling demand for captive fossil-fuel power plants to supply energy-intensive nickel processing, which sees a significant increase in captive power.
While a Presidential Regulation** bans new coal-fired power plants developments to accelerate RE, it includes an exception that permits the continued construction of these captive plants for the industrial sector.
IPP received the larger share of coal investment at around $4.9 bn (61% of total coal investments), mostly in market-rate loans. Meanwhile for gas, IPP received $0.4 bn with a larger share of $2.5 bn for captive power (500MW) to Bahodopi Vale Nickel Smelter Gas power station.
With $7.2 bn or 55% of total FF investment, international private FIs were by far the largest contributor. Meanwhile, domestic private FIs contributed $5 bn, mostly to IPP coal-fired power plants (such as the Jawa-9 and Jawa-10 each at 1 GW capacity).
Foreign Concessional loan (USD 0.6 bn) involvement is notable comprising of
- Korean Dev Bank (USD 0.4 bn) – Java-9&10 CFPPs
- IFC & ADB (USD 0.1 bn) – Riau Gas powerplant
- China Dev Bank (USD 0.1 bn) – Xiamen Xiangyu Nickel Mine – Gas power captive
IPPs received the largest share of RE financing, with $4.0 bn from private FIs and $1.0 bn from public FIs.
Meanwhile, PLN received more funding from public sources of RE financing, from public FIs ($1.25 bn) and private FIs ($0.85 bn). For large projects, the Upper Cisokan Pumped Hydro project.
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 bn) followed by market-rate loan ($1.5 bn), while geothermal received a larger share of concessional loan ($0.6 bn) followed by equity ($0.3 bn).
Funding Flows to PLN
Operational costs were mainly from PLN-owned plants.
Coal plants accounted for both the largest share of annual operating costs (~46%) and of annual production (65%).
Gas and diesel also incurred significant costs (~34% and ~16% respectively) but contributed far less to annual production (~21% and ~6% respectively), indicating higher costs of production.
Except for hydro and solar, fuel contributes the most to operational costs per unit production.
PLN’s FF power plants have high operational costs, which include Diesel at (IDR 2.5K/kWh), Gas (IDR 1.4K/kWh), and Coal (IDR 0.6K/kWh). In contrast, its RE power plants show varying but generally lower costs, with Geothermal (IDR 0.9K/kWh), Hydro (IDR 0.1K/kWh), and Solar PV (IDR 3.1K/kWh). Please note, the referred operational costs are for PLN-Owned Power Plants only, which may significant change if we add IPP operational costs.
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 0.6k/kWh to IDR 1.2k/kWh).
PLN’s solar plants produce far less electricity based on Capacity Factor (CF) than they should, as compared to Independent Power Producers (IPPs) and against other plant types, making them inefficient and costly.
Capacity factor refers to the ratio of a power plant’s actual output over a certain 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 is needed to identify the root cause and to develop strategies to close the gap between the capacity factor of PLN-owned solar PV and its IPP’s and regional benchmark, which can potentially reduce PLN operational cost significantly (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 $1.79 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.
