Indonesia, a key player in the global energy transition, faces surging electricity demand and ambitious renewable energy goals. In response, the government introduced a new regulation about renewable energy tariffs, including tariffs for photovoltaic (PV). However, there remains a gap in the academic literature regarding PV power plant feasibility studies under these tariffs. To address this gap, this study investigates the feasibility of a utility-scale solar photovoltaic (PV) power plant in Indonesia, focusing on the newly implemented renewable energy tariffs based on Independent Power Producers (IPPs) and Indonesia's state-owned electricity company (PLN) perspectives. Five scenarios were developed based on the proposed 26 MW solar power plant on Nias Island utilizing RETScreen software. The results showed that based on the IPP perspective, the newly implemented renewable energy tariff was inadequate to make the project feasible, however, an introduction of a 10 USD/t CO₂ emission incentive would make the project financially viable for IPPs. Therefore, it is recommended to introduce emission incentives as a strategic approach to attract investors and stimulate investment in Indonesia's PV power plants market, to accelerate Indonesia's energy transition. Conversely, the results also showed that the project is very profitable for PLN due to the significant cost-savings from the de-dieselization, leading to a reduction in the average generation cost for Nias.

In an attempt to accelerate the energy transition, the government of Indonesia released a new regulation regarding renewable energy tariffs, including for biomass power plants (BPPs). However, a gap persists in the academic literature focusing on biomass power plants under these new tariffs. This study examines the role of biomass power plants (BPP) in meeting Indonesia's renewable energy targets, with a specific focus on recently introduced renewable energy tariffs. Three scenarios were developed to comprehensively understand Indonesia's state-owned electricity company (PLN) perspective and Independent Power Producers (IPPs) perspective, with a case study in Kundur Island, Riau Province. The financial analysis for IPPs shows in an NPV of $1.8 million under the initial tariff, while the expansion tariff results in an NPV of -$0.3 million. Sensitivity analysis reveals that a capacity factor exceeding 94.5 % is required to yield a positive NPV under the expansion tariff. From PLN's perspective, BPPs under the initial tariff correspond to an NPV of $8.48 million, and a B-C ratio of 2.31, resulting in a financially viable project, due to substantial cost savings from de-dieselization. Furthermore, the emission analysis highlights an 83.7 % decrease in emissions emitted with the utilization of BPPs compared to diesel power plants. These findings underscore the need to incorporate average generation cost in formulating renewable energy tariffs. Ensuring renewable energy projects are economically sustainable for both PLN and IPPs, stimulates widespread adoption and sustains cost-savings, all while advancing energy transition and making energy more accessible for everyone.

This study conducts feasibility study on 3.5 MW photovoltaic (PV) power plant in Nusa Penida based on Indonesia’s existing renewable energy tariffs. Three scenarios were developed utilizing RETScreen software, according to the power plant specification. Base case scenario was developed to determine the feasibility of the PV power plant based on independent power producer perspective. PLN scenario was developed to determine the feasibility of the PV power plant based on Indonesia’s state-owned electricity company. Clean-energy scenario was developed to determine the feasibility of the PV power plant if there was a $20/tCO2 emission reduction incentive in Indonesia. The base case scenario results showed that the existing PV tariffs for PV power plant project was not sufficient to make the project financially viable based on the IPPs perspective. The PLN scenario results showed that the PV power plant project is very profitable based on PLN perspective due to high cost-savings. The clean-energy scenario results showed that $20/tCO2 emission reduction incentive was sufficient to make the PV power plant project financially viable based on the IPPs perspective. Based on those results, this study recommends emission-reduction incentives as a mean of attracting more investors. This study also recommends PLN to utilize more PV power plant, especially if the region have high generation cost as a means to lower Indonesia’s energy cost thus making energy more accessible for everyone.

In Indonesia, the power generation sector is the primary source of carbon emissions, largely due to the heavy reliance on coal-fired power plants, which account for 60% of electricity production. Reducing these emissions is essential to achieve national clean energy transition goals. However, achieving this initiative requires careful consideration, especially regarding the complex interactions among multiple stakeholders in the Indonesian electricity market. The electricity market in Indonesia is characterized by its non-competitive and heavily regulated structure. This market condition often requires the PLN, as the system operator, to address multi-objective and multi-constraint problems, necessitating optimization in the generation dispatch scheduling scheme to ensure a secure, economical, and low-carbon power system operation. This research introduces a multiparadigm approach for GS optimization in a regulated electricity market to support the transition to clean energy. The multiparadigm integrates multi-agent system and system dynamic paradigms to model, simulate, and quantitatively analyze the complex interactions among multiple stakeholders in the Indonesian regulated electricity market. The research was implemented on the Java–Madura–Bali power system using AnyLogic 8 University Researcher Software. The simulation results demonstrate that the carbon policy scheme reduces the system’s carbon emissions while increasing the system’s cost of electricity. A linear regression for sensitivity analysis was conducted to determine the relationship between carbon policies and the system’s cost of electricity. This research offers valuable insights for policymakers to develop an optimal, acceptable, and reasonable power system operation scheme for all stakeholders in the Indonesian electricity market.

This article proposes a method for determining the optimal reclose scheme in power systems. The proposed approach involves analyzing multiple parameters such as the voltage and phase angle difference between bus, critical clearing time (CCT) of the systems, power surge of connected generators in the system, secondary arc duration in the systems, fault-induced delayed voltage recovery (FIDVR) phenomenon, and transient recovery voltage (TRV) in circuit breaker. Each parameter is assessed individually, and the results are compared with a matrix scoring system to determine the appropriate reclose scheme for each parameter. Subsequently, the reclose schemes derived from each parameter are integrated to identify the most effective reclose scheme for each segment of the system. This approach ensures that all relevant factors are considered in selecting a reclose scheme that optimally balances the system’s stability, reliability, and performance under various conditions. This methodology provides a more robust reclose scheme by considering a comprehensive set of factors, leading to enhanced the system stability and reliability. This study utilized DIgSILENT PowerFactory, providing a detailed examination of the Batam-Bintan transmission system. It is shown that the proposed method shortens the deadtime by 2 seconds in most single-phase reclosing schemes and 1 three-phase scheme, and mitigates the system instability risk on 3 three-phase reclosing schemes. The method presented serves as a valuable guide for determining optimal reclose schemes in both distribution and transmission systems, contributing to more effective fault recovery strategies and improved network performance.

HVDC is a promising interconnection solution for connecting asynchronous systems and ensuring power control. In Indonesia, a remote industrial system in Sumatra is experiencing load growth and has the option to draw power from the Sumatra system. However, due to frequency differences, the use of HVDC is crucial. The Generation Expansion Planning has proposed six converters but not their interconnection points. This study will determine the most reliable interconnection locations. The chosen converters are modular multilevel converters (MMCs) with high modularity. The converter reliability modeling considers voltage levels, the number of modules, and redundancy strategies. This modeling is then implemented at the power system level to obtain the best placement at the available high-voltage (HV) substation options. Determining the best placement is based on the optimal reliability index. The optimal placement also includes the option to convert from HV to medium-voltage (MV) interconnection. MV interconnection offers higher flexibility but tends to be more expensive. The availability for HV converters is 99.69%, while for MV converters, it is slightly higher, at 99.81%. Additionally, converting from HV to MV reduces the SAIFI (system average interruption frequency index) from 0.2668 to 0.2284 occurrences per year, lowering the interruption cost from 7.804 million USD to 5.737 million USD per year. The sensitivity of interruption, investment, and maintenance costs shows that converting at least one HV converter to MV remains economical. In this case study, the optimal converter placement includes Area VI–2, recommended for conversion from HV to a more distributed MV configuration, improving reliability and economic efficiency.