Expanding electricity access and reliability is a top priority for Africa. Roughly one in two people still live without electricity, and growing economies are increasingly in need of electrons.¹ Moving every low-income and lower-middle-income country to upper-middle-income will require an estimated 8,700 terawatt-hours (TWh)² of growth in electricity consumption. This is roughly twice the current annual generation in the United States and a $400 billion – $1.3 trillion per year revenue opportunity if electricity is priced between $0.05 and $0.15 per kWh. African electricity demand is the fastest moving among this group, and it is set to grow more than fourfold by 2050 if governments meet their announced targets (Exhibit 3.1).

Exhibit 1

Delivering power at least cost requires physical infrastructure, such as the solar panels and batteries in clean energy portfolios, as well as the information infrastructure that allows these components to work together. Emergent climate tech is part of both dimensions. On the physical infrastructure side, innovations in long-duration energy storage, for example, will be crucial to a stable grid with a high penetration of variable renewable resources. On the information infrastructure side, the distributed energy resources (DERs) on the grid need to coordinate with these energy storage resources to route excess power to storage, for example, to an iron-air battery or distributed EV batteries owned by customers participating in a vehicle-to-grid program. This piece focuses on the information infrastructure, with the view that emergent climate tech is key to building the intelligent, flexible, and interconnected grids that can wring the most value from the physical infrastructure of today — and of the future.

Electricity grids across the continent are struggling to meet current customer demands. In 2025, most traditional utilities in Africa are manually operating analog electricity systems, with limited knowledge of who their customers are and where their assets are located.

In Nigeria, only 25% of the 12 gigawatts (GW) of installed generation capacity is available due to constraints in generating, transmitting, and distributing power to customers.³ Further, only about half of the electricity there that is distributed to customers is ultimately billed and paid for: in a granular energy audit of the Port‑Harcourt distribution network, billing efficiency stood at only 68.6% and collection efficiency at 76.3%, resulting in an Aggregate Technical, Commercial, and Collection (ATC&C) loss of 49.5%.⁴ Data from the Nigerian Electricity Regulatory Commission routinely find ATC&C losses ranging from 40%–50% across utilities.⁵ Most of these distribution networks are operated with manual switches and interfaces. Under these conditions, the difference between overloading a transformer or shutting down safely can come down to whether someone looks at readings on site and makes a phone call to decide when to throw a switch.

If Nigeria’s grid could deliver its full installed capacity (versus 25% today) and eliminate ATC&C losses (nearly 50% today), utilities could generate eight times more revenue — without building a single new power project.

More broadly, only 16 of the 70 utilities in sub-Saharan Africa generate enough revenue to cover their costs.⁶ African utilities building out their infrastructure in the coming decades have access to new tools to build better grids and feed them cheap power. The cost of “clean energy portfolios” — comprising wind, solar, battery storage, energy efficiency, and demand flexibility — has fallen 80% since 2010 and is competitive with new natural gas power plants while providing the same grid reliability services. In Nigeria, we estimate the opportunity for grid-tied DERs at roughly 22 GW over the next 10 years in the least-cost path to meeting growing demand.⁷

A more intelligent, flexible, and interconnected grid is the key ingredient in integrating these DERs. Specifically, the people who operate the grid need to be able to see what is happening across the network, anticipate potential problems, and prevent or solve these problems. Beyond managing the grid that is already built, digital tools can also enable better planning for future infrastructure investments by making today’s problems visible and then simulating the effects of various improvements. Leveling up these capabilities will require a mosaic of hardware and software solutions that create the grid of the future.⁸

Utilities can benefit from innovation in sensing, intelligence, and controls, and their needs will vary as they progress. Their priorities can be roughly categorized into three phases in order of urgency, constituting a type of “utility hierarchy of needs,” as presented in Exhibit2:

• Phase 1: Stabilizing system performance by understanding the customer base, clearly seeing grid infrastructure, and improving service to and collections from existing demand.

• Phase 2: Modernizing grid function to increase reliability, resilience, and operational efficiency; and to enable DER integration.

• Phase 3: Transforming the electricity system to enable new business models such as virtual power plants, to ensure both distributed and centralized resources are maximized and reliable, and to enable customer choice in how they get and manage their power use.

Exhibit 2

Exhibit 2 summarizes several innovation areas, grouped by their function and classified according to the phases above.

Improving grid visibility through mapping and simulation

Utilities need to know what’s on their grid to operate it today and make plans for tomorrow.

“We really need something like a Google Drive for energy. We need a place where the information about the energy system is organized, easy to access, correct, and where you can collaborate on it.”

—Page Crahan, General Manager, Tapestry⁹

Making the grid visible improves operations and service quality now and sets the foundation for a more flexible grid in the future. Grid mapping and simulation can generate more accurate data, which allows faster outage detection and prevention, improves forecasting, and provides a basis for long-term planning. Having a clear map of the grid allows on-ground and office staff to look at a common reference point and coordinate better. Advanced metering infrastructure (AMI), a core component of grid visibility, also sets the foundation for more dynamic operations down the line, enabling automated control of the grid and demand response.

For grid mapping, companies like Beacon Power Services use software technologies and human surveyors to develop detailed data on grid assets and customers that utilities can use to improve operational performance. For example, in Ghana, Beacon helped a utility double revenue in just 18 months by finding 180,000 customers that were on the grid but not being billed, and by pinpointing a troublesome transformer that needed better management to prevent overloading and outages.

Using Grid-Enhancing Technologies (GETs) to make the most of existing power systems

GETs expand the capacity of the grid faster and more cheaply than upgrading grid infrastructure, making this an impactful near-term solution to reduce grid capacity constraints and accelerate interconnection of new clean generation.¹⁰ These solutions include hardware and software tools that increase the capacity, efficiency, and flexibility of the existing grid by using real-time, localized information on the state of the grid (situational awareness) to automate how much and where electricity flows, including:

• Dynamic line ratings that adjust the carrying capacity of grid lines based on real-time measurement of ambient conditions such as air temperature, wind speed, and solar radiation

• Advanced power flow controls, which are hardware solutions that physically push power away from lines with capacity constraints toward lines with spare capacity

• Topology optimization, which automatically diverts power away from congested areas

• Digital twin technology, which enables real-time monitoring of grid assets to support maintenance, operation, and planning

GETs have been widely used in Europe for decades and have a long track record of proven performance.¹¹ Companies like Enline use digital twin technology to enable dynamic line ratings, maintenance planning, power optimization, and short-term overload prevention. With operations across five continents, including Africa, Enline has optimized over 10,000 km of lines and 20 GW in generation assets, increasing energy production by 40,500 TWh and generating $3 billion in additional revenues.¹²

GETs are also a building block for a more flexible renewable energy system in the future. They improve utilities’ situational awareness, which enables them to assess the localized impact of dispatching specific DERs on the grid, and to orchestrate DERs at wider levels of adoption (i.e., when they reach 5% to 15% of distribution system peak).

Exhibit 3

Combining and controlling DERs to optimize grid flexibility and resilience

Utilities can aggregate DERs and optimize dispatch alongside centralized (front-of-meter) assets. This capability becomes more important with wider adoption of DERs on the grid (e.g., 15+% of distribution system peak), and it builds on the foundation of the functionalities unlocked by the technologies described above. For instance, the grid must be capable of two-way communication with consumer devices like solar systems, water heaters, and EVs, as well as remote and automated control of these devices. The grid also needs clear situational awareness of customer loads via AMI and GETs. This means investing in technologies that enable utilities to control, manage, and orchestrate DERs, including integrated distribution planning, situationally aware distributed energy resource management systems (DERMS), or DERMS combined with grid orchestration platforms and grid-forming inverters.

This is a longer-term opportunity that will require higher levels of DER adoption and regulatory change to enable a level playing field for all resources. Some of these changes include:

• A system of market-determined prices and charges for electricity services that reflect the marginal cost of supplying electricity services

• Incentives that reward utilities for cost savings, performance improvements, and innovation

• A level playing field for generators, network providers, and developers to competitively provide electricity services

Practically, the benefits that these technologies can offer African grids today are constrained by the ability of utilities to absorb them. These constraints can be grouped into four categories:

1. Physical infrastructure: Utility digitization can only solve so much — at some point, utilities will need more conductors and will need to replace failing and underperforming equipment. Advanced sensing, controls, and intelligence are only valuable as part of a holistic investment in grid capacity.

2. Human capacity: Digital solutions must be implemented by people — whether utility staff members or a third party such as the companies mentioned in Exhibit 3. Utilities in Africa often lack knowledge of suitable solutions and connections to capable technology service providers.

3. Affordability: Struggling utilities have limited funding options and access to low-cost capital to invest in these technologies. Investors need proof points showing how strategic investments in improved capacity can achieve a return.

4. Regulation: Today’s policies do not always incentivize (or allow) innovation, especially on technologies that have not been widely adopted elsewhere (i.e., Phase 3 of our Utility Hierarchy of Needs).

Interventions to kick off virtuous cycles of grid improvement, revenue generation

Today’s grid operators are tasked with reversing a vicious cycle of low reliability, unhappy customers, low collections, and falling revenues. A first step to overcoming this inertia is to show evidence of a grid improvement kick-starting a virtuous cycle of better service, better collections, and rising profitability. However, for the 80% of sub-Saharan African utilities that do not collect enough revenue to cover their costs, financing these initial investments can be scarce.

Most utilities will need some external help: an intervention that overcomes the affordability gap for this initial investment in the human, hardware, and software capacity that can start them on the road to recovery. A catalytic investment in AMI and grid mapping, for example, can begin to address the ATC&C losses and lack of grid awareness that stand in the way of system stabilization (i.e., Phase 1 in the Utility Hierarchy of Needs). Crucially, these interventions must invest in the utility’s capacity to own and maintain these improvements over time.

Globally, the IEA estimates that the annual average investment in grids needs to more than double from an estimated $330 billion in 2023 to around $750 billion by 2030.¹³ However, the share of investment in grids in emerging and developing economies has fallen in the last decade. Programs such as the Digital Demand-Driven Electricity Networks (3DEN) Initiative and AFD’s Digital Energy Facility are supporting projects that can reverse this trend. But more catalytic support is needed, particularly in Africa, to meet the moment.

Partnerships with developers and technology service providers to supplement utilities’ human and financial capacity

Partnerships can build utilities’ ability to implement these solutions, helping them side-step funding constraints by bringing a credible third party that can unlock new sources of capital and expertise. For example, many companies in Exhibit 3 offer creative financing or revenue sharing business models that reduce the upfront cost to utilities. Providing project preparation support and embedding expert staff in utilities can build capacity to plan and roll out digitization technologies. Providing this bespoke support through projects provides a place for these technologies to land, demonstrate their impact, and set a precedent that other utilities can follow.

Policy and regulation

Utilities can move from analog to digital and integrate low levels of DERs (less than 5% of distribution system peak) without significant changes to regulatory and policy frameworks. In fact, utilities are eager to upgrade grid infrastructure and operations to meet regulatory mandates stemming from the recent wave of regulatory changes unbundling utilities in sub–Saharan Africa. However, at wide-scale adoption levels, where DERs can be aggregated and operated as power plants, regulations will need to evolve to recognize and allow cost-reflective prices and charges for the different types of services that DERs, including demand response, provide. A policy framework that rewards utilities for cost savings and innovation can lay the pathway toward this future state.