When measured against its regional peers, Elektroprivreda Srbije (EPS) is increasingly lagging—not in stated ambition, but in execution speed, project scale, and repeatable delivery capacity. The contrast is clearest in renewables, flexibility, and grid-linked investments, where neighbouring utilities have moved from planning into multi-year construction cycles, while EPS is only beginning to transition from feasibility-heavy portfolios into first operational assets.
EPS can still point to one major recent delivery: the 350 MW Kostolac B3 lignite unit, commissioned at the end of 2024. It is a tangible asset and proof that EPS can execute large, complex projects when contracts are locked and political priority is clear. But it also illustrates the structural problem. Kostolac B3 took around seven years to build, belongs to the coal generation era, and does not address the system bottlenecks that now define competitiveness in the 2026–2030 window—namely, flexible low-carbon capacity, grid-ready renewables, and fast-cycle project delivery.
On renewables, EPS is only now entering operational territory. The company connected its first wind farm, Kostolac (66 MW), to the grid in late 2025. Its first utility-scale solar plant, Petka (around 10 MW), also came online in 2025. These milestones matter institutionally, but in regional terms they are starter projects, not scale platforms. They represent learning steps rather than an established execution pipeline.
By comparison, several regional utilities have already moved decisively into industrial-scale build-out mode.
In Greece, the public power utility has repositioned itself as a renewables-led energy company with a clearly defined capital cycle. Its current investment framework covers more than €10 billion of capex over a three-year period and targets multiple gigawatts of new renewable capacity within that same timeframe. Crucially, this is not presented as an aspirational list but as a sequenced delivery programme, supported by recurring EPC awards, portfolio financing, and standardized project structures.
Croatia’s power utility operates on a smaller absolute scale than Greece, but its execution discipline is stronger than EPS’s in proportional terms. Annual investment programmes consistently exceed €600 million, with renewable projects and grid upgrades reaching financial close through structured loans involving European policy banks. The key difference is not size but conversion speed: projects move from planning to construction without multi-year stagnation in feasibility stages.
Romania represents a different but equally instructive benchmark. Its main state power producer is already low-carbon due to hydro dominance, so its direct capex is focused on refurbishment and selective additions rather than massive greenfield build-out. However, Romania has shifted the heavy lifting of new capacity to market mechanisms, using Contracts for Difference and auctions to mobilise billions of euros in private investment. The result is system-level execution at scale, even if the state utility itself is not the sole builder. EPS, by contrast, is still expected to be the primary execution vehicle for Serbia’s transition, without comparable market pull mechanisms operating at scale.
Hungary’s integrated state utility offers yet another comparison. There, capital expenditure has risen sharply in recent years, supported by stable policy alignment and long-term financing. Large network modernisation programmes and generation investments are backed by clear funding channels and multi-year delivery schedules. Again, the distinguishing factor is not rhetoric, but visible, rolling investment cycles.
EPS does articulate forward-looking numbers. Its public planning documents refer to several billion euros of investment through the end of the decade, including more than €2 billion in renewables and around €1 billion in hydropower upgrades and new capacity. But these figures remain strategic envelopes, not yet matched by a corresponding flow of signed EPC contracts, grid connection works, or construction milestones. The fact that EPS’s first wind and first solar plants only entered operation in 2025 underscores how early the organisation still is in building an internal renewables execution machine.
The gap becomes even clearer in system flexibility, the critical enabler of large-scale renewables. EPS’s flagship flexibility project, the Bistrica pumped-storage hydropower plant (around 650 MW), is widely recognised as strategically essential. Yet it remains dominated by feasibility work, permitting discussions, and financing concepts. Cost estimates exceed €1 billion, but construction timelines extend into the next decade. While EPS debates sequencing, regional peers are already integrating flexible capacity in parallel with renewables deployment, not years afterward.
So is EPS lagging? Yes—relative to regional competitors that have shifted from planning to industrialised execution. EPS has demonstrated that it can deliver mega-projects under special circumstances, but the energy transition does not reward one-off builds delivered over a decade. It rewards repeatability: dozens of standardized projects, financed, built, and connected on predictable cycles.
The challenge for EPS is not technical competence but institutional throughput. Until feasibility studies give way to a rolling pipeline of awarded contracts, grid reinforcements under construction, and renewable capacity commissioned every year—not once per decade—EPS will continue to trail peers that have already adapted their execution models to the new energy economy.