Energy

Kamoa-Kakula copper project (Image source: Ivanhoe Mines)

Germany’s DHYBRID Power Systems GmbH has reported on its work supplying the battery energy and storage system (BESS) and control platform for the Kamoa-Kakula copper complex in the Democratic Republic of Congo (DRC)

It marks Africa’s first solar baseload plant, delivering 30 MW of power around the clock, and has already saved the mine site US$11mn during the first month of operations.

The Kamoa-Kakula copper project is owned and operated by Ivanhoe Mines, which also gave an update on the project in its Q3 results recently (Kamoa-Kakula on-site power costs tumble).

Sixteen months after a power purchase agreement was signed, DHYBRID’s Universal Power Platform (UPP) coordinates 233 MWp of solar and a 526 MWh battery system at the complex into a guaranteed 30 MW of baseload energy, 24 hours a day, seven days a week, with peaks of 55 MW.

In its first month of operation, the plant displaced around 4 million litres of diesel, DHYBRID noted in a statement.

DHYBRID engineered the battery system and provides the control platform for the facility that CrossBoundary Energy developed, owns and operates at the site, near Kolwezi.

The UPP is the central control layer for the entire plant, according to the company: 513 photovoltaic inverters, 90 battery inverters, 180 battery containers, more than 200 power quality meters, protection relays, meteorological sensors, UPS and HVAC units, and more than 400 managed network switches, over 1,300 devices in total.

“For the operator, the power output of the plant is controlled by one button: ask for 30 MW and you get 30 MW, ask for 50 MW and you get 50 MW of stable output,” said Tobias Reiner, CTO and managing director of DHYBRID Power Systems GmbH.

“Our forecasting algorithm tells the operator 24 hours ahead what the plant can deliver, and the UPP holds that setpoint by coordinating more than 1,300 devices in real time to make sure intermittent solar power becomes renewable, reliable baseload.”

Four OEMs, one plant

The facility combines 357,048 Aiko solar modules, Sungrow photovoltaic inverters and medium-voltage stations, Risen SYL battery containers and EPC Power power conversion systems.

None of the four makes the control layer. DHYBRID’s platform is manufacturer-independent by design, which let CrossBoundary Energy choose each component on its merits and still operate the result as a single power plant.

The same platform runs DHYBRID systems at more than 100 sites in around 30 countries, from Maldivian atolls and critical infrastructure in Europe to the Rio Tinto QMM mine in Madagascar and mulitple Nigerian Breweries projects.

DHYBRID also customised the 180 battery containers for the project’s logistics, including road-weight limits on the 3,080 km route from Durban port to Kolwezi.

Each unit was factory-tested in China before shipping and commissioned on site by engineers.

The plant exported its first electricity in June 2026, 13 months after site access, and reached commercial operation on 12 August.

CrossBoundary Energy expects the facility to produce around 300,000 MWh a year and avoid roughly 78,750 tonnes of carbon dioxide annually.

Planned expansion work

Separately, DHYBRID has been awarded the contract to expand the Kamoa-Kakula battery system by a further 35 MWh to an installed capacity of 561 MWh, with commercial operation targeted for January 2027.

The additional capacity will be integrated into the existing control layer without changes to the plant’s operating interface.

Kamoa-Kakula plans to further raise its on-site solar baseload capacity to 120 MW within 18 months.

Founded in 2013, DHYBRID is headquartered in Gauting near Munich and has a subsidiary in Midrand, South Africa.

EAAIF commits US$18.15mn to Ghana's 100MWp solar project

The Emerging Africa & Asia Infrastructure Fund (EAAIF), a Private Infrastructure Development Group (PIDG) company managed by Ninety One, has committed US$18.15mn in financing to Ghanaian conglomerate LMI Holdings

The funding, channelled through its subsidiaries Solar for Industries Ltd (SFI) and Enclave Power Company Ltd (EPCL), will support the construction and operation of a 100MWp ground-mounted solar photovoltaic (PV) plant in Dawa, Ghana.

The facility will provide lower-cost renewable electricity to more than 95 energy-intensive manufacturers operating in the Tema Free Zone and Dawa Industrial Zone.

The financing consists of US$15.65mn from EAAIF and US$2.5mn from Ninety One’s Africa Credit Opportunities strategy. SFI has been established as a special-purpose vehicle focused on solar generation, while EPCL serves as LMI Holdings’ principal operating utility. EPCL is Ghana’s first and only licensed private electricity distributor, offering an alternative to reliance on state off-takers and demonstrating a privately operated utility model for Africa’s energy transition.

The project’s first phase has a total cost of US$88.6mn. The International Finance Corporation (IFC) led the financing, contributing a direct loan of US$24.2mn and working with EAAIF, Ninety One and the World Bank’s International Development Association (IDA) to mobilise a further US$60.6mn in debt. LMI Holdings provided the remaining US$28mn through an equity investment.

During Phase 1, the 100MWp solar plant is forecast to produce 129.5 GWh of electricity annually. EPCL will transmit the generated power over approximately 40 kilometres of Ghana’s national grid under a Transmission Service Agreement (TSA), delivering electricity to more than 95 industrial customers in the Tema Free Zone and Dawa Industrial Zone.

The development is expected to advance industrial decarbonisation while supporting LMI Holdings’ backward integration strategy. By providing a more predictable and affordable electricity supply to manufacturers in Ghana’s key industrial hub, the project aims to reduce indirect greenhouse gas emissions and improve the environmental credentials and export competitiveness of businesses in sectors such as cocoa, cement and steel.

Exports represent approximately 35% of Ghana’s GDP, making reliable and competitively priced energy an important factor in sustaining the performance of export-oriented industries.

The project also contributes to Ghana’s Renewable Energy Master Plan, which targets a 10% share for renewables in the country's electricity generation mix by 2030. It is consistent with PIDG’s 2023–2030 Strategy, which focuses on expanding climate finance, transforming markets and mobilising private investment across emerging economies.

Martijn Proos, co-head of Emerging Market Alternative Credit, Ninety One, the fund manager of EAAIF, stated: “This transaction highlights EAAIF’s commitment to financing transition infrastructure that accelerates green growth and delivers affordable, reliable power to Ghana’s manufacturing heartland.”

Kojo Aduhene, founder, chairman, and CEO of LMI Holdings, said, “Following the success of our 16.8MWp Helios Solar rooftop project in Tema, we are privileged to be part of this structural evolution in Ghana’s power and energy sector by effectively demonstrating how private innovation can drive the nation’s sustainable economic development.”

Nathalie Kouassi Akon, IFC division director for West Africa Gulf of Guinea, said, “Ghana’s clean energy transition is also an investment in the country’s industrial growth and competitiveness. This solar project will help manufacturers lower electricity costs and reduce emissions strengthening their capacity to expand production, create jobs, and compete in regional and global markets ”

Powering up the DRC's Kamoa-Kakula mine (Image source: Ivanhoe Mines)

Ivanhoe Mines has reported that the new on-site hybrid solar photovoltaic (PV) facility at its Kamoa-Kakula mine in the Democratic Republic of Congo (DRC) is expected to slash energy costs by US$0.10/lb. to US$0.20/lb. of payable copper produced

In its Q3 update, it noted that the on-site power plant with battery energy storage system (BESS) was fully ramped up by the end of the quarter, delivering 60 MW of continuous baseload electricity to the DRC complex.

“This is expected to reduce energy costs by $0.10/lb. to $0.20/lb. of payable copper produced, as Kakula dewatering is switched over from being powered by back-up diesel generators, to the new facility in mid-October,” the company reported in early November.

Kamoa-Kakula is now advancing plans to double baseload power from the hybrid solar facilities to 120 MW by the end of Q1 2028.

Two tenders, totalling 60 MW, were awarded, along with accompanying power purchase agreements (PPA) signed in Q2 and Q3.

In addition, discussions are underway to expand the existing hybrid solar facilities by a further 30 MW, bringing total on-site planned capacity to 150 MW, Ivanhoe Mines added.

Founder and co-chairman Robert Friedland said operational improvements made are now delivering tangible results.

“Our phased investment in solar power is already displacing very expensive diesel-powered generation,” he said.

“These structural improvements will strengthen Kamoa-Kakula’s competitiveness long after our current challenges have been overcome.”

Kipushi zinc mine

A similar blueprint is in place to provide power for its Kipushi zinc mine as well.

The tender for Kipushi’s hybrid solar PV project is expected to be awarded in the first quarter of 2027, the company said in its Q3 update.

The facility will be designed to provide 10 MW of continuous baseload power, providing approximately 50% of the site’s energy needs.It is expected to be operational by mid-2028 and will “significantly reduce diesel consumption from on-site backup generators,” the statement added.

Since quarter-end, Kipushi’s operations have also been supported by an additional 10 MW of grid-supplied power from third-party providers.

“The additional power is expected to reduce power instability at Kipushi and reduce power costs from the back-up diesel generators,” the company noted.

Incorporating distributed energy resources into Africa's grid (Image source: Adobe Stock)

With Africa’s energy makeup increasingly decentralised, driven by the advent of rooftop solar, electric vehicles (EVs) and energy storage resources (ESRs), utilities are facing a fundamental challenge – how do they connect more distributed energy resources (DERs) to the grid without compromising its stability? By Nishandra Bajinath, digital grid, head of sales in sub-Saharan Africa at Schneider Electric

As more customers become energy producers as well as consumers, the traditional approach to managing electricity networks is being tested. Previously, the national grid was largely designed around a relatively predictable model of centralised generation flowing through transmission and distribution networks to customers.

Today, customers may consume electricity, generate it, store it and — where regulations and connection arrangements allow — export it back into the network, resulting in power flowing bi-directionally, while the amount of generation connected at the edge of the network can change significantly from one customer to the next.

This introduces greater variability and more complex power flows at the grid edge. The opportunity is significant, but unlocking it requires utilities to understand not only where distributed resources are connected, but also how they affect the network under different operating conditions.

From connecting DERs to understanding their impact

One of the most important questions is how much additional generation, storage or flexible demand can be hosted in a given part of the network while ensuring utilities keep it safe and reliable?

A comprehensive system-level review on Energy Transition Resilience Gaps published in ScienceDirect outlines that current operational metrics are completely fragmented. Operators face massive “major event blind spots” because existing data tracking fails to properly integrate cyber-physical interdependencies and dynamic, localised grid realities.

And it is here where visibility becomes critical A traditional electricity network may have relatively stable physical infrastructure: high-voltage (HV) substations, medium-voltage (MV) and low-voltage networks, ring main units and other assets whose characteristics are well understood.

The DER landscape, by contrast, is highly dynamic. One household may have an 8-kW inverter, another a 5-kW system, while another may have additional batteries or a different combination of solar panels and storage.

At the commercial and industrial level, the diversity multiplies; factories may deploy large‑scale storage and shopping centres may integrate rooftop PV with demand response programs, and municipalities may be using microgrids.

If you multiply this across thousands of customers, utilities are suddenly dealing with a huge volume of assets and data.

A new operational environment

Utilities therefore need intelligence that can help them understand the electrical characteristics of their networks, assess available hosting capacity and identify where additional DER connections could create constraints.

Schneider Electric’s EcoStruxure Distributed Energy Resource Management System (DERMS), for example, combines DER monitoring, forecasting and control with capabilities such as hosting capacity analysis, grid constraint management and the use of DER flexibility to address network needs.

This allows utilities to become more proactive, understanding where DERs can be connected, what their impact could be and how their flexibility can be used to support the network.

DERMS should be understood as part of a wider Digital Grid environment. SCADA provides telemetry, alarms and authorised field control. EcoStruxure ADMS — or EcoStruxure Grid Operation for smaller and medium-sized utilities — provides the operational network model, distribution analysis, switching and outage-management environment. DERMS complements these systems with DER-specific visibility, forecasting, orchestration and constraint-aware dispatch.

Together, these capabilities can help operators understand where DER is connected, how it is expected to behave and where future conditions may create voltage, thermal or reverse-power-flow constraints.

Turning flexibility into a grid asset

The real opportunity lies in moving beyond simply monitoring DERs to actively using their flexibility to support the network.

Solar generation, batteries, EVs, microgrids and demand-response programmes can all become part of a more flexible electricity system. When coordinated effectively, these resources can help utilities respond to changing network conditions, manage constraints and maximise renewable generation. DERMS can aggregate these resources, evaluate their available flexibility and dispatch individual or grouped resources in response to local or wider system needs.

This does not mean that every rooftop installation, EV or battery is automatically controllable. Participation depends on communications, equipment capability, customer consent, connection agreements, aggregator arrangements and the applicable regulatory framework.

This is particularly important because high levels of renewable generation can introduce challenges such as reverse power flows, voltage issues and thermal constraints. Digital tools can provide utilities with greater situational awareness, helping them identify potential problems in real time as well as anticipate upcoming constraint violations.

Planning for a more distributed energy future

Traditionally, when network capacity becomes constrained, reinforcement may mean building or upgrading physical infrastructure. As DER penetration increases, however, utilities can also consider whether the flexibility available from distributed resources can help manage constraints before capital-intensive reinforcement becomes necessary.

Again, EcoStruxure DERMS supports this approach by enabling utilities to assess different grid reinforcement scenarios, including their technical and economic feasibility, while analysing different levels of DER adoption and their impact under varying load and weather conditions.

The greatest value will come from connecting planning and operations: accurate GIS and network models, SCADA and metering data, DER forecasts, ADMS-based grid awareness, outage-management processes, and DERMS-based flexibility orchestration.

That is how power utilities can move from simply accommodating DER to actively integrating them into a safer, more flexible and renewable-ready electricity system.