18.09.2026
Ukraine is short of electricity. But that is not the whole problem.
At the same time, the power system is gaining more and more resources that could help during hours of scarcity: utility-scale and household batteries, distributed generation, businesses able to shift their load, and, in the future, hundreds of thousands of controllable household devices and electric vehicles.
Yet physically having a resource and being able to use it are two different things.
For a notional 100 MW to help the system today at 7:00 p.m., it is not enough to know that those megawatts exist somewhere. The system must know where they are, whether they will be available at 7:00 p.m., whether the local network can accommodate their activation, and who is authorised to call on them.
This may be the central challenge of Ukraine’s Smart Grid transition. Many individual components already exist, but they have not yet been fully converted into one controllable, coordinated system.
In a power system facing scarcity, that distance is measured not only in years or billions of hryvnias. It is also measured in megawatts that could be valuable to the system but are not yet reliably available in the right place at the right time.
Ukraine has made substantial progress in recent years. At the top level of the power system, modern digital dispatch and control tools are in operation. Ukrenergo’s SCADA data and synchronised measurements are integrated into ENTSO-E’s operational information environment. Ukraine’s power system operates as part of the synchronous area of Continental Europe.
New technologies are also advancing rapidly. In 2025, six large battery energy storage systems with a combined power rating of 200 MW and energy capacity of 400 MWh were commissioned. A significant share of that capacity was intended to provide ancillary services to Ukrenergo.
Distribution networks are deploying telecontrol, automated switching equipment and smart meters. Local generation is expanding. Legislative changes adopted in 2026 significantly broadened the legal possibilities for aggregation, demand response and the use of flexibility.
This is genuine progress.
But it creates a potentially costly misconception: installed equipment can easily be mistaken for an achieved capability.
A meter may be digital while its data are not yet used for demand response. A remotely controlled switch may be installed while the network is still unable to identify a fault, isolate the affected section and restore supply automatically. A battery may be connected, while its system value still depends on whether it is available at the required moment and capable of delivering the required function.
Between a decision to deploy a technology and a system-level outcome lies an entire chain:
rules → equipment → integration → functional readiness → actual use → system outcome.
Viewed this way, the main conclusion becomes clear: Ukraine’s Smart Grid is not simply developing slowly. It is developing unevenly.
And the largest remaining distance is increasingly shifting from the central dispatch level towards distribution networks and the millions of resources connected to them.
The traditional power system was relatively easy to visualise: several dozen large power plants, transmission networks, distribution networks and millions of mostly passive consumers. Information and commands flowed mainly from the top down.
The emerging system is fundamentally different.
Electricity is increasingly produced close to consumers. A consumer may simultaneously own rooftop solar and a battery. An industrial facility can alter its load profile. An electric vehicle becomes a significant controllable load and, potentially, a flexibility resource.
This means that a distribution system operator must gradually evolve from managing largely passive infrastructure into an Active DSO: an operator able to observe its network, forecast power flows, manage local constraints and interact with distributed energy resources.
The central system dispatcher should not control every household battery directly.
Between the national dispatch centre and individual resources, a new operational layer is emerging: distribution system operators, aggregators, virtual power plants and local resource-management systems.
The maturity of the Smart Grid will therefore increasingly be determined by the quality of interaction between these layers, not simply by the number of digital devices installed.
This is particularly important for a country facing a capacity shortage.
Solar generation may produce substantial electricity during the day but decline in the evening. A battery can shift energy between hours. An industrial consumer can temporarily reduce demand. Thousands of water heaters, heating systems, chargers, batteries and other controllable loads can collectively become a significant resource.
For the power system, this is a new form of reserve. Building another power plant is not always the only way to gain additional balancing capability at a particular moment.
But there is a critical detail – Flexibility has three coordinates: how much, where and when.
A megawatt available at noon may not help at 7:00 p.m. A megawatt in one part of the network may not resolve congestion elsewhere. Conversely, a battery, generator or controllable consumer located behind a constrained local line may be more valuable than a much larger resource located far away.
It is therefore not enough to know that a resource exists.
The system must be able to observe it, forecast it, locate it within the network, check whether activation is network-admissible, activate it, measure the response and verify the result.
This is where an aggregator turns thousands of small resources into a controllable portfolio. This is where the distribution operator must determine whether the local network can accommodate their use. And this is where coordination with the national system operator becomes essential.
A resource that the system cannot see, forecast or safely activate practically does not exist for the system at a critical hour.
Ukraine can therefore face an apparent paradox: a shortage of capacity while simultaneously underusing some resources that already physically exist within the power system.
A Smart Grid cannot reverse the destruction of generation caused by Russian attacks. But it does determine how effectively the country can use what remains and what it builds anew.
It would be a mistake to explain the uneven development of Ukraine’s Smart Grid only through technology. Technologies do not integrate themselves.
The Ministry of Energy shapes state policy. NEURC establishes regulatory rules and economic incentives. Ukrenergo is responsible for system balance and reliability. Distribution system operators manage their networks. Investors build generation and storage. Aggregators are expected to combine distributed resources.
Each has its part of the job.
But the Smart Grid emerges between them.
The analysis identifies three systemic gaps.
The first is a transformation governance gap.
Who is responsible not for an individual project, regulation or completed measure under the Smart Grid Concept, but for ensuring that all these results converge into one functioning system?
In other words, is there a state-level mechanism responsible not merely for coordinating individual measures, but for achieving the target functional state of Ukraine’s power system?
The second is a transformation timing gap.
Distributed generation, batteries and other local resources are appearing now. The war has sharply accelerated decentralisation. Yet network observability, forecasting, digital platforms and coordination mechanisms take time to develop.
As a result, the physical architecture of the energy system is changing faster than the architecture used to manage it.
The third is an accountability gap.
Someone is responsible for procuring a meter. Someone else installs it. Someone transmits the data. But who is accountable for ensuring that those data ultimately create the function required by consumers, the market and the power system?
Someone installs distribution automation. But the final outcome is not an automated device listed in a report; it is a section of network capable of locating a fault faster and restoring supply.
Likewise, the final outcome of aggregation is not a provision in legislation. It is megawatts that can actually be activated and verified.
A battery has an owner. A network has an operator. The power system has a dispatcher. Rules have a regulator. State policy has a ministry. But the Smart Grid emerges between them.
If accountability ends at the boundary of each organisation, the final outcome can be lost precisely between those boundaries.
Energy resources can be decentralised. State responsibility for the direction of the transformation cannot.
Rebuilding Ukraine’s entire power system in two or three years is impossible. But that is the wrong way to frame the task.
Ukraine does not need to wait for complete network modernisation before it begins to capture Smart Grid benefits.
In 2026–2028, the key task should be to create complete operational loops linking the national system dispatcher, an active distribution operator, an aggregator and batteries, distributed generation, industrial facilities or active consumers.
And they should be tested through operations, not presentations.
A shortage or local network constraint occurs. Can the system identify an available resource? Does it know where the resource is? Can it be used without violating network limits? Can it be activated? Did the expected response occur? Can that response be measured and verified?
If the answer is yes, this is no longer a digitalisation pilot. It is a verified system capability.
In 2028–2030, such solutions should move from individual operational loops to scaling: distribution automation, practical use of smart-metering data, aggregation, demand response, local flexibility and coordination between system operators.
The period 2030–2035 should then become the phase of system integration, when verified mechanisms become the normal operating model of the Ukrainian power system.
2035 can therefore be the horizon for a mature Smart Grid.
But it cannot be the year when Ukraine only begins learning how to operate a decentralised power system.
The obvious answer is more investment. Investment is indeed necessary.
But not every Smart Grid problem can be solved through additional CAPEX.
It is possible to procure another hundred thousand meters, another hundred automated devices or another battery more quickly. It is much harder afterwards to make equipment from different generations, software platforms, operators and market participants function as one coherent system.
Ukraine therefore needs to change the unit by which transformation is measured.
Not the number of devices installed, but the system capability they create.
For every critical function, the country should define what the system must be able to do, who is accountable for the outcome, what data and technologies are required, how functionality will be verified, and when the solution must be scaled.
This also changes the logic of investment.
Not:
procured → installed → reported.
But:
needed → created → integrated → verified → operational → scaled.
That is the difference between digitising equipment and managing the transformation of the power system.
Ukraine is not starting its Smart Grid journey from zero. A substantial part of the technological foundation already exists, while the war has paradoxically accelerated the development of decentralised energy.
But that is precisely why there is less time.
The faster the number of distributed resources grows, the more costly the lag becomes in the systems required to observe, forecast and coordinate them.
A Smart Grid moves at the speed not of its strongest technology, but of the weakest critical links between technologies.
In a system with ample capacity, such immaturity would primarily cost money.
In a system facing scarcity, it can cost hours of electricity supply.
The central question is therefore no longer whether Ukraine will have a Smart Grid by 2035.
The more important questions are: what will actually work by 2028? What will be scaled by 2030? Who is personally and institutionally accountable for those outcomes? And how many potentially useful megawatts will remain underused if critical decisions are postponed until 2035?
For a power system facing scarcity, the result of digital transformation can ultimately be tested with four simple questions:
How much resource do we have? Where is it? When is it available? And can we use it?
The answer is not needed in 2035.
It is needed today.
