Performance of a solar PV-diesel generator-battery mini-grid using actual data: a case of Kalangala power plant in Uganda

Abstract

Decentralized hybrid solar photovoltaic systems present a viable option for rural electrification, especially for regions where solar irradiance is high, but grid connectivity is not feasible. In this study, the performance of a 1.6 MW solar photovoltaic–Diesel generator hybrid Mini grid located at Bukuzindu village, Bugala island in Kalangala district, Uganda was assessed. The system’s monthly energy data for the period from July 2019 to June 2023 was collected and analysed. The findings showed that the average monthly electricity generated by the plant was 203.1 MWh, of which 174.1 MWh, 22.4 MWh, 0.96 MWh, and 5.4 MWh, respectively, were distributed to consumers, accounted for generation and transmission losses, consumed at the plant site, and used to charge the battery bank system. The solar PV performance ratio and capacity factor were found to be 65.6% and 13.4%, respectively. Meanwhile, the mini grid capacity factor and overall combined generation and transmission loss were 17.39% and 11.03%, respectively.

1 Introduction

Access to affordable, reliable, and modern electricity remains a major global development challenge. More than 620 million people worldwide lack access to electricity, with the greatest burden concentrated in Sub-Saharan Africa, where more than half of the population remains without access to clean and modern energy services (Ayua and Emetere, 2024). This persistent energy deficit has significant implications for socioeconomic development, given the well-established positive relationship between electricity consumption and economic growth (Lawal et al., 2020), (Oliveira et al., 2024). Reliable electricity is essential for productive activities, healthcare, education, communication, water supply, and the development of modern industries; consequently, expanding access to dependable and sustainable electricity is central to achieving inclusive economic development.

Uganda continues to face significant challenges in expanding access to modern energy, particularly in rural and remote communities. According to the 2024 National Population and Housing Census, Uganda has a population of approximately 45.9 million people (Uganda Bureau of Statistics, 2024).

Despite ongoing investments in the energy sector, the country’s final energy consumption remains overwhelmingly dependent on solid biomass, primarily firewood and charcoal, which account for approximately 86% of total final energy consumption. Petroleum products and electricity contribute approximately 11% and 2%, respectively (IEA, 2025). This heavy dependence on biomass has significant environmental and socioeconomic consequences. Uganda’s forest cover has declined substantially, from an estimated 54% in 1900 (Nafula, 2023) to approximately 13.3% in 2022 (NPA, 2024). In addition, reliance on firewood and charcoal for cooking exposes households, particularly women and girls, to household air pollution associated with adverse respiratory health outcomes (Wafula et al., 2023).

Although Uganda’s overall electricity access has increased to approximately 60%, a substantial proportion of this access is provided through small-scale solar technologies rather than conventional grid connections. Grid electricity access at the household level remains considerably lower, at approximately 25.3%, with rural household access estimated at only 9.1%, compared with 49% in urban areas (Murungi et al., 2025). This disparity is particularly significant because approximately 73% of Uganda’s population resides in rural areas (WorldBank, 2024). Extending the national electricity grid to remote and sparsely populated communities is often technically and economically challenging because of the substantial investment required for transmission and distribution infrastructure, substations, and associated network facilities (Wassie and Adaramola, 2021). Consequently, decentralized electricity systems, including solar photovoltaic (PV) mini-grids and hybrid renewable energy systems (HRES), provide an important alternative for improving electricity access in areas where conventional grid extension is not economically viable.

At the same time, Uganda has made considerable progress in expanding its electricity-generation capacity. Installed generation capacity increased more than threefold over the past 15 years, from approximately 595 MW in 2010 (NPA, 2024) to more than 2,000 MW by 2025 (ERA, 2026a). As shown in Table 1, Uganda’s electricity-generation portfolio remains strongly dominated by hydropower, with large and small hydropower plants accounting for the majority of installed capacity. Solar PV, despite its considerable potential and versatility, continues to represent a relatively small proportion of the country’s installed generation capacity.

Solar energy has applications extending beyond electricity generation, including agricultural-product drying, water pumping for irrigation, food and vaccine preservation, and water and space heating (Ayua et al., 2023). With an average daily solar radiation of (Aarakit et al., 2021), Uganda is particularly well positioned to exploit solar energy. Nevertheless, as shown in Table 1, solar PV accounted for only 88.28 MW of the country’s installed generation capacity as of September 2025 (ERA, 2026a). This relatively limited contribution highlights both the underutilization of Uganda’s solar resource and the potential for further deployment of solar-based electricity systems, particularly in areas underserved by the national grid.

Solar energy as reported by (Ayua and Camara, 2024) is particularly attractive for hybrid energy systems because of its ability to complement conventional and other renewable energy sources. Solar PV can be integrated with grid electricity, diesel generators, wind turbines, and battery storage in configurations such as PV/grid, PV/diesel, PV/wind, PV/wind/diesel, and PV/wind/battery systems (Ayua and Camara, 2024). Such hybridization can improve system reliability, reduce dependence on fossil fuels, lower greenhouse-gas emissions, and improve the quality and continuity of electricity supplied to consumers (Ayua and Camara, 2024). For remote communities, these characteristics make HRES particularly relevant as an alternative to either diesel-only generation or costly grid extension.

In Uganda, decentralized renewable-energy systems have consequently emerged as viable options for rural electrification, particularly where connection to the national grid is technically or economically impractical. The country currently has more than 46 operational mini-grids, with a combined installed capacity of approximately 3.871 MW, most of which are based on solar PV technology (NREP, 2024). Although the installed capacity of these systems remains relatively small compared with the national generation portfolio, their strategic importance is considerable because they can provide electricity to geographically isolated communities while reducing reliance on conventional fossil-fuel-based generation.

The strategic importance of solar energy is further reinforced by Uganda’s long-term energy-development plans. The Uganda Energy Policy 2023 and Uganda Vision 2040 envisage a substantial expansion of the country’s electricity-generation capacity, reaching approximately 52.4 GW by 2040 (MEMD, 2023). Of this projected capacity, approximately 12 GW is expected to come from solar PV, representing about 23% of the planned generation mix. As shown in Table 2, the projected generation portfolio also includes substantial contributions from nuclear, hydropower, natural gas, geothermal, green hydrogen, biomass, wind, and other sources. The planned expansion indicates that solar-based electricity systems are likely to become an increasingly important component of Uganda’s future energy landscape.

The increasing deployment of decentralized solar and hybrid energy systems makes the assessment of their actual operational performance particularly important. Technical performance evaluation provides evidence on the extent to which installed systems deliver their expected energy output and can reveal operational losses, equipment degradation, underperformance, and other factors affecting system reliability and sustainability. Such evidence is also important for informing the design, sizing, operation, maintenance, and future deployment of HRES in rural electrification programmes.

Several studies have evaluated the technical performance of photovoltaic systems using measured operational data. For example (Dobaria et al., 2016), assessed a 5.05 kWp grid-connected PV system in Rajkot, India, and reported final yields ranging from 2.96 to 5.43 h/day, reference yields from 4.22 to 7.29 h/day, and performance ratios of 68%–83%, with an annual average energy yield of 1,636 kWh/kWp (Banda et al., 2019). evaluated an 830 kWp grid-connected PV plant at Kamuzu International Airport in Malawi using measured and simulated data and reported a 4-year average performance ratio of 79.2% and a capacity factor of 17.7%. Similarly (Al-Badi, 2018), evaluated a 1.4 kWp grid-connected PV system at Sultan Qaboos University in Oman and reported annual energy production of 2,217.6 kWh, a performance ratio of 65%, and a capacity factor of 17%.

Other studies have reported comparable performance assessments for PV systems in different climatic and operational environments (Sharma and Goel, 2017). evaluated an 11.2 kWp grid-connected PV system in Bhubaneswar, India, over 1 year and reported annual energy production of 14.960 MWh and a performance ratio of 78% (Sharma and Chandel, 2013). assessed a 190 kWp PV plant at Khatkar-Kalan, India, reporting an annual average performance ratio of 74%, a capacity factor of 9.27%, and system losses of 31.7%. In Ireland (Ayompe et al., 2011), analysed a 1.72 kWp rooftop grid-connected PV system over a 1-year monitoring period and reported an annual energy yield of 885.1 kWh/kWp, a performance ratio of 81.5%, and a capacity factor of 10.1%.

Compared with grid-connected PV systems, considerably less empirical evidence is available on the long-term operational performance of off-grid PV mini-grids, particularly hybrid systems supplying isolated communities. An important example is the study by (Wassie and Ahlgren, 2023) which investigated the actual performance of a 375 kWp off-grid PV mini-grid installed in a remote Ethiopian town using measured weather, power-generation, and load data. The system generated approximately 1,182 kWh/day compared with an estimated 2,214 kWh/day, representing a shortfall of approximately 46%, and achieved a capacity factor of 13%. The overall system efficiency was reported as 8.76%, indicating significant operational underperformance. However, the study was based on only 8 months of operational data, which may not adequately capture seasonal variations and long-term operating characteristics of an off-grid PV mini-grid.

The existing literature therefore demonstrates a clear imbalance in the evidence base. While numerous studies have assessed the performance of grid-connected PV systems, relatively few have investigated the long-term, measured performance of off-grid solar PV–diesel hybrid systems operating under the environmental, load, and operational conditions characteristic of rural Sub-Saharan Africa. In particular, there is limited empirical evidence from Uganda based on several consecutive years of actual operational data. This is an important knowledge gap because the performance of hybrid systems can vary substantially with solar resource availability, load demand, diesel-generator operation, system configuration, maintenance practices, equipment condition, and seasonal conditions. Short-duration assessments may consequently fail to capture important variations in system performance.

This study addresses this gap by evaluating the technical performance of the 1.6 MW Kalangala Solar PV–Diesel Hybrid Power Plant, an off-grid hybrid electricity-generation system located on Kalangala Island, Uganda. Unlike studies based primarily on simulations or short monitoring periods, this study uses 4 years of actual operational data to assess the performance of the hybrid system. The analysis provides empirical evidence on the system’s energy generation and technical performance over an extended operating period and offers insights into the operational characteristics of an off-grid PV–diesel–battery hybrid system in a remote Ugandan setting. The findings are intended to contribute to improved planning, design, operation, maintenance, and performance evaluation of decentralized hybrid renewable-energy systems and to support their wider adoption as a technically and economically viable pathway for rural electrification in Uganda and similar developing-country contexts.

2 Methods and materials

2.1 Installation site and overview of the power plant

The Kalangala solar PV-diesel hybrid power plant was commissioned in December 2014 and is in Bukuzindu village, Mugoye sub-county, on Bugala Island in Kalangala district, Uganda. The plant is located 17 km from Kalangala town on a latitude 0.305 S and longitude 32.15 E. Figure 1 shows the map of Uganda and the location of the power plant. Currently, the power plant supplies electricity to over 5,523 domestic and 67 commercial customers, including hotels and small enterprises (ERA, 2025). The power plant was constructed at an estimated cost of US$17 million (Bindhe, 2025).

FIGURE 1

Google, 2023).

2.2 Components of the hybrid power-generating station

The power plant has a total installed capacity of 1.6 MW, with the solar PV system contributing 0.6 MW and 1.0 MW from diesel generators. Other major components of the power plant include 4 grid-connected inverters, 2 bi-directional inverters, maximum power point tracking (MPPT) charge controllers, a battery system, and a 2 MVA substation. The generated power is distributed using a 144 km medium-voltage distribution network and 180 km low-voltage distribution network (ERA, 2024). Figure 2 shows the power plant layout with the capacity of each of these main components, while Figure 3 presents selected photos of the solar PV installation and the substation.

FIGURE 2

KIS, 2024).

FIGURE 3

2.3 Design, arrangement, and connections

The solar system component comprises a solar PV system, battery bank, charge controllers, and inverters. The solar PV system is made up of 2832 PSS 235Wp modules, and it is divided into three units. The first unit (Unit 1) comprises 1,920 modules and is subdivided into 4 arrays, with each array comprising 480 modules and connected to a 125-kW grid inverter (with model number APOLLO GTP-507). The key technical specifications of the modules are shown in Table 3.

Table 4 shows selected specifications for grid-connected inverters. Each array is arranged as 15 modules per string with a total of 16 strings in 2 parallel rows per grid inverter. This results in a total PV open circuit of 555 V and a voltage at the maximum power point of 472.5 V. This total PV open circuit voltage is slightly higher than the inverter’s maximum input voltage per string of 550 V, however, the total per string is within the maximum power point tracking (MPPT) voltage range of 270–500 V of the inverter. To protect the inverters from over voltage, a high voltage cut-off of 480 V was set. The total short circuit current of each array in Unit 1 is 268.8A, which is lower than the grid-connected inverter’s maximum input current of 465A.

The second unit (Unit 2) comprises 900 modules and is subdivided into 3 arrays, with each array connected to a charger controller (MPPT Solarcon SCM-480200 charge controllers) (see Table 5), which charges the battery bank. Each array is arranged as 15 modules per string and 20 strings per charge controller, with 300 modules. The total PV short-circuit current is 168A, which is lower than the charge controller’s maximum input current of 200A. However, the total PV open circuit voltage is 555 V, slightly higher than the charge controller’s maximum open circuit voltage of 552 V.

The battery bank is connected to the MPPT solar charge controllers and two bi-directional inverters via the DC busbar. The battery bank is made up of 2 strings, with each string comprised of 240 batteries. Each battery is rated as 686 Ah, 2 V @10 h. This results in total battery capacity and string voltage of 1372 Ah and 480 V, respectively or 658.56 kWh. The battery model used is Hoppecke Sun Power VL 2-910 (see Table 6 for selected specifications). Each bi-directional inverter (MTP-6113G) is rated 200 kVA. The bi-directional inverters link the AC bus and DC bus. Table 7 shows the selected specifications of the bi-directional inverters. In the original design of the power plant, the batteries played a buffer role, storing excess energy during low demand and releasing it when the system needs excess power (KIS, 2024). However, the island has since outgrown the battery capacity, thus they are currently only being used to power the plant site, including the bi-directional inverters, MPPT charge controllers and computers (Uganda, 2023).

The plant has three diesel generators rated 500 kVA, 320 kVA, and 200 kVA. The output from the diesel generators and grid-connected inverters is fed to the 1,500A AC bus, which in turn feeds a main substation of two 1 MVA transformers. Power from the substation is then fed through a 33 kV distribution line to two main feeders.

2.4 Data collection and monitoring

The power plant has a data logger, which is used for monitoring and recording energy output from the solar PV system, energy output from diesel generators, and other weather-related data. The plant also has a pyranometer, which measures in-plane solar irradiation on the solar PV system. Monthly power plant output and weather data from July 2019 and June 2023 were collected from the plant facility’s manager during a site visit. However, solar irradiation data were only provided for the period between July 2019 and June 2022. The power output data collected includes monthly energy generated by the solar PV and diesel generators, energy consumed at the power plant station, energy used for charging the battery bank, energy dispatched to the transmission network, and energy delivered to the distribution network.

2.5 Analysis approaches and performance indices

The technical performance analysis of the hybrid power plant is divided in two groups: (i) the technical performance of the solar PV system and (ii) the overall performance of the hybrid power plant.

2.5.1 Solar PV plant performance indicators

The performance of a Solar PV system can be studied by assessing several technical performance indicators. The technical indicators demonstrate the overall efficiency of the system, subject to the technical properties of the installation’s components and site environmental conditions. The essential indicators are final energy output, performance ratio, and capacity factor. The final energy output of a solar PV system can be determined as shown in Equation 1 (Mensah et al., 2019), (Al-Najjar et al., 2022), (de-Lima et al., 2017), (El Hacen Jed et al., 2020):where is the energy generated by the solar PV system at time . The value of depends on the resolution of available data.

The performance ratio (PR) is defined as the ratio of the final energy yield of the PV system () to the reference, yield () (Kumar and Sudhakar, 2015). It indicates the overall effect of losses on the solar PV system’s normal power output. The PR indicates how close the system approaches ideal performance during real operation, hence allowing comparison of PV systems independent of location, tilt angle, orientation, and their nominal rated power capacity (de-Lima et al., 2017). It is given as presented in Equation 2:

The reference yield is defined as the total in-plane irradiance divided by the reference irradiance, which is given as 1 . The reference yield is the number of peak sun hours or solar radiation in . The is a function of the location, tilt angle, and orientation of the solar PV system, as well as ambient conditions (such as ambient temperature, wind speed, and air condition) of the solar PV installation and solar PV technology (such as temperature coefficients).

The final yield () is defined as the annual, monthly, or daily final energy output of the solar PV system divided by its installed power capacity at standard test conditions, and it is mathematically expressed as indicated in Equation 3:

The overall solar PV system losses () can be expressed as a function of the performance ratio as follows (see Equation 4):

The capacity factor (CF) is the ratio of actual energy produced () by a power plant over a given period to the energy output that would have been generated if the system operated at installed capacity () for the entire period. The annual capacity factor of a power plant is given in Equation 5 (Mensah et al., 2019), (de-Lima et al., 2017), (Kumar and Sudhakar, 2015):where is the total duration in hours (mostly taken as 8760 h for annual duration). Equation 5 can be used to estimate the solar PV system, diesel generator, and overall power plant capacity factors.

2.5.2 Diesel generator performance indices

Renewable energy systems have intermittent energy output characteristics. As such, they are often integrated with conventional power sources to deliver stable power output. The use of diesel generators in grid-connected systems assists in supporting load peaks and reduces or eliminates the need for a battery system (or reduces the capacity of the battery system). The energy output of the diesel generator is given by Equation 6:

2.5.3 Hybrid plant performance indices

For a hybrid solar-diesel system, the generated energy is the sum of energy generated by the solar PV array () and the diesel generators () and it is given as Equation 7 (Al-Najjar et al., 2022):

The actual energy dispatched by the combined generators over a given period is expressed as given in Equation 8.where is the amount of energy generated but not delivered at the point of transmission, and in this study, it is given as in Equation 9:where is the energy consumed at the power plant premises, is the technical loss on the generation side, and is the energy used for charging batteries. The energy delivered to the consumers (measured at the transformers) is expressed as Equation 10:where is the amount of energy dispatched but not delivered to the consumers. Therefore, the overall system loss is expressed as in Equation 11:

The overall performance (efficiency) of the power plant can be expressed as the actual energy delivered to the consumers relative to the actual energy generated by the power plant from all the power generators (Al-Najjar et al., 2022). It is given as Equation 12:

Alternatively, the power plant efficiency can be expressed as Equation 13:

3 Results and Discussions

3.1 Electricity generation

Figure 4 shows the monthly electricity generated by the solar PV (SPV) system, diesel generator, and the contribution of the solar PV system to the monthly electricity generation from June 2019 and July 2023. The electricity generated by the SPV system varied between 49.2 MWh (in November 2022) and 83.3 MWh (in July 2022), with an overall average of 65.5 MWh per month. In addition, the electricity generated by the diesel generators varied between 85.02 MWh (in June 2020) and 240.18 MWh (in November 2020), with an overall average of 137.15 MWh per month. The high energy output from diesel generators could be attributed to the electrical load demand that is usually higher in the evening period, since most electricity consumers in Bugala Island are residential households. In addition, within the period considered in this study, it is observed that the monthly SPV system contribution ranges between 23.67% (in November 2020) and 86.12% (in June 2020) with an average monthly contribution of 49.69%. As can be observed in Figure 4, the percentage contribution of the SPV system is inversely proportional to the diesel generator output.

FIGURE 4

The variability coefficient, defined as the ratio of the standard deviation to the average value, is estimated as 10.29%, 18.48%, and 11.57% for the SPV system, diesel generators, and hybrid system, respectively. Therefore, the power output from the hybrid power plant can be considered relatively constant over the studied period. This information could be useful to forecast the future energy output from the power plant.

Figure 5 shows the average monthly electricity generated by the hybrid power plant and SPV system, as well as the average monthly contribution of the solar PV system. On average, the power plant generated a minimum of 187.83 MWh and a maximum of 229.55 MWh of electricity in June and December, respectively, with a monthly average of 203.01 MWh. Furthermore, the average total energy output of the hybrid power plant is estimated as 436.08 MWh. In addition, it is observed that, on average, the solar PV (SPV) system generated a minimum of 56.18 MWh and a maximum of 74.29 MWh of electricity in November and July, respectively, and a monthly average of 65.56 MWh. The monthly coefficient of variation (CoV) of 6.63% indicated that monthly SPV system generation is moderately constant from January to December. The contribution of the SPV peaked in July (with 37.96%) and attained the lowest value of 24.61% in November.

FIGURE 5

3.2 Electricity delivered and losses

Figure 6 shows the percentage of the electricity delivered to the distribution system, losses in generation and transmission systems, energy used for charging the battery, and energy consumed at the power plant site. The percentage of electricity delivered to the grid relative to electricity generated by the hybrid power plant ranges between 83.79% (in February) and 89.17% (in November), and an annual monthly average of about 86%.

FIGURE 6

The peak in transformer-metered energy observed in November 2020 may be attributed to several factors. First, the Ugandan government eased COVID-19 restrictions on 9 November 2020 (Wanambwa, 2020), which likely led to increased electricity demand on the island as businesses resumed operations, particularly in the tourism sector and other commercial enterprises on which the island’s economy heavily depends. A second possible explanation, according to the plant manager, is that a palm oil processing factory requested a continuous electricity supply from the power plant after its steam turbine—the factory’s primary source of electricity generation—broke down during this period. This would have resulted in increased demand. However, there is no publicly available evidence confirming that this event was responsible for the observed increase in electricity consumption.

It can also be observed that the combined auxiliary, generation, substation, transmission, and distribution losses range from 8.66% in November to 13.21% in February, with an annual average of 11.03%. Of the total electricity generated, approximately 0.50% is consumed by auxiliary plant loads, while 2.72% is used to charge the battery bank system.

The mini-grid supplies Bugala Island through a 33 kV distribution network. For this study, generation losses refer to energy consumed within the generating station, including auxiliary plant loads and battery charging as well as auxiliary generation losses. In contrast, distribution losses refer to technical losses incurred during power delivery through the substation and 33 kV distribution network.

The reported loss is a combination of generation loss (average of 3.13%) and distribution loss (average of 7.90%). On the other hand, between 2021 and 2025, the Ugandan national grid recorded average transmission losses of 4.42% and distribution losses of 17.74% ((ERA, 2026b), (ERA, 2026c)), with total combined average losses of 22.16%. The mini-grid’s technical distribution losses are substantially lower than the national grid’s average distribution losses, indicating more efficient power delivery within the local network. Therefore, the observed losses in the mini grid are considered acceptable. Furthermore, the main transmission line for the mini grid is a 33 kV distribution network, which is a distribution voltage line under Uganda’s voltage classifications.

3.3 Capacity factor and solar PV performance ratio

The monthly capacity factor of the solar PV system, diesel generators, and overall hybrid power plant, as well as the performance of the solar PV systems, are presented in Figure 7. The capacity factor represents the ratio of the actual energy generated over a given period to the energy that would have been produced if each component of the mini grid operated continuously at its rated capacity. It therefore provides an indication of the extent to which each component is utilized relative to its maximum possible energy output.

FIGURE 7

It can be deduced from Figure 7 that average annual capacity factors are 13.44%, 18.88%, and 17.39%, respectively, for the solar PV system, diesel generator, and overall hybrid power plant. The relatively low-capacity factor of the solar PV system (13.44%) is primarily associated with the intermittent nature of solar energy resources. Solar PV generation is limited to daylight hours and is further influenced by solar irradiance variability, cloud cover, seasonal changes, module temperature, and system losses. The diesel generator capacity factor of 18.88% indicates that the generator operates for a relatively small proportion of its rated capacity over the year. This is expected in a hybrid mini grid where diesel generation serves primarily as a dispatchable backup source rather than the main energy supplier. The lower utilization level reflects the operational strategy of prioritizing renewable energy generation while using the diesel generator during periods of insufficient solar production, high demand, or system contingencies. This reduced operating time contributes to lower fuel consumption, reduced emissions, and extended generator lifetime.

The solar PV mini-grid achieved an annual average Performance ratio (PR) of 65.62% as shown in Figure 7, indicating that approximately two-thirds of the theoretical energy available from the incident solar radiation was converted into useful electrical energy after considering system losses. The PR provides a direct measure of the technical performance of the PV system by evaluating the actual energy yield relative to the expected output under standard test conditions.

In comparison with the findings of Wassie and Ahlgren (Wassie and Ahlgren, 2023) of a mini-grid system in southern Ethiopia, the performance of the present study is better. The mini-grid capacity factor and performance ratio of the solar PV system for Wassie and Ahlgren are 13.0% and 42%, respectively. However, the performance ratio and capacity factor of the solar PV system are lower than those of the Soroti solar PV plant, at 75.84% and 19.07%, respectively (Oloya et al., 2021). The low-capacity factor and performance ratio of the power plant, compared to the Soroti Solar PV plant, could be due to the plant having a lower average daily radiation of 4.94 kWh/m squared/day, compared to the Soroti Solar PV plant at 5.85 kWh/m which is 5.85 kW/ /day. Other factors could include dust accumulation given the plant’s close proximity to the main road, inverter conversion losses, battery storage losses, and additional power electronics losses in the hybrid mini-grid system.

4 Conclusions and recommendations

4.1 Key findings

A technical performance study of a 1.6 MW Solar PV–Diesel hybrid system installed in Bugala Island, Kalangala district, Uganda, was conducted using real-time energy generation and transmission data as well as measured irradiance of the location. The collected data used in the analysis were for 4 years between June 2019 and May 2023.

The findings showed that on average, the mini-grid power plant generated 2436.1 MWh annually, with a monthly average of 203.1 MWh, of which 174.1 MWh, 22.4 MWh, 0.96 MWh, and 5.4 MWh, respectively, are distributed to the consumers, used for generation and transmission losses, consumed at the plant site, and used to charge the battery bank system. The overall combined generation and transmission loss of the power plant is reported as 11.03%, while the solar PV system contributed 32.5% of the electricity generated by the plant. Analysis of the system’s losses showed that the solar-diesel hybrid system’s transmission line loss (7.9%) was higher and almost double that of the annual national average of 4.2% during the same period.

The solar PV system’s annual performance ratio and capacity factor are 65.6% and 13.4%, respectively, while the mini-grid system has a capacity factor of 17.39%. The hybrid system is close to a busy dusty road, hence the need for routine cleaning.

4.2 Policy recommendations

The study results indicate that transmission losses on the island’s mini-grid are 7.9%, substantially higher than the national grid average of 4.42%. This elevated loss level is likely associated, among other factors, with the continued operation of a 33 kV transmission system under increasing electricity demand. At higher loading levels, the relatively low transmission voltage results in increased current flow and consequently higher power losses. At medium-voltage transmission levels, 33 kV networks are suitable for relatively long-distance power transfer where the distance and load do not justify higher transmission voltages. Published studies report the application of 33 kV lines over distances ranging from approximately 30 km–60 km. For example, 33 kV lines of 30 km and 40 km have been analysed in electrical-network studies (Igbinovia et al., 2019), while practical grid-extension projects have implemented 33 kV lines of approximately 50–60 km (JICA, 2006). The economically and technically feasible distance, however, depends on factors such as transmitted power, conductor size, voltage regulation, losses, and system configuration.

The island’s transmission network, however, currently extends to approximately 144 km, while electricity demand continues to increase. This combination of long transmission distances and growing demand places additional loading on the existing 33 kV infrastructure and is likely to contribute to the observed technical losses and voltage-performance challenges. It is therefore recommended that the Government and relevant electricity-sector stakeholders undertake a detailed feasibility and system-planning study to upgrade the island’s principal transmission network from 33 kV to 66 kV. The proposed upgrade should be supported by load-flow, voltage-drop, fault-level and economic analyses to determine the optimal configuration, conductor requirements, substation locations and investment requirements. Increasing the transmission voltage would reduce current for a given power transfer and, consequently, reduce resistive transmission losses, improve voltage regulation and provide greater capacity for accommodating the island’s projected growth in electricity demand.

The upgrade should be implemented as part of a long-term transmission reinforcement strategy, rather than solely as a response to the current loss levels, to ensure that the island’s electricity infrastructure remains reliable, efficient and capable of supporting future economic and social development.

4.3 Limitations and future research

This study had some limitations, thus affecting the possibilities of assessing certain performance aspects. For example, the Levelized Cost of Electricity and payback period could not be assessed since the distribution tariff for the plant has only been declared for the period up to quarter one of 2022, and yet the data used in this study is for the period up to July 2023.

Future research is crucial to conduct a detailed techno-economic performance analysis of hybrid renewable energy systems in Uganda; however, this requires that data on tariffs be updated frequently. Similarly, the performance of other hybrid solar photovoltaic plants needs to be carried out to assess their performance in terms of financial and technological viability.

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