EPS’ solar-plus-storage push reframes Serbia’s power transition around flexibility

Serbia’s energy transition is moving beyond the idea of adding renewables in isolation. Elektroprivreda Srbije (EPS) is instead shaping a system-scale solar and battery platform intended to deliver both new generation and the flexibility needed to keep a coal-heavy grid stable—while aligning with EU electricity and carbon rules.

The starting point remains the country’s legacy power mix. Lignite-fired assets, especially those in the Kolubara and Kostolac basins, still account for more than 60–65% of domestic electricity generation in typical hydrology years. That structure provides baseload security, but it also leaves the system exposed to rising carbon costs, operational inefficiencies and growing maintenance capital expenditure. At the same time, seasonal hydropower swings create balancing needs that conventional generation alone cannot fully address.

A hybrid buildout designed to manage volatility

In response, EPS has adopted a dual-track approach: deploying utility-scale solar quickly while running a parallel rollout of battery energy storage systems. The solar pipeline currently in development or tendering is estimated at 1–2 GW, with project clusters in central and eastern Serbia sized between 100 MW and 300 MW. EPS is structuring these developments either through EPC-led arrangements with international contractors or via hybrid PPP-style models that involve strategic partners.

The investment case reflects both global cost compression and local execution realities. Solar assets in Serbia are being developed at roughly €600,000 to €800,000 per MW, depending on grid connection complexity and land configuration. Using a midpoint of about €700,000/MW, a 1 GW portfolio implies approximately €700 million in capital expenditure, while scaling to 2 GW would bring the figure toward €1.4 billion.

Batteries change economics—and how projects are valued

But solar output alone does not resolve system constraints tied to Serbia’s demand profile—winter peaks paired with increasing intraday volatility. Storage is therefore positioned as an operational backbone rather than an add-on. EPS is evaluating and initiating projects totaling roughly 500–1,000 MWh, with deployments planned across key substations and generation nodes.

The current battery CAPEX range cited for these efforts is €400 to €600 per kWh. Depending on final scale and configuration, that translates into an overall investment envelope of about €200–500 million. The role of batteries extends beyond simple arbitrage: they are intended for multi-service stacking including frequency regulation, peak shaving, congestion management and balancing support.

This flexibility also feeds directly into project finance assumptions. Standalone solar projects can reach base-case IRRs of roughly 8–10%, assuming average captured prices around €60–75/MWh. When paired with battery storage—enabling peak-price capture alongside ancillary services—the IRR potential rises toward 11–14%, depending on dispatch strategy and market conditions.

Grid limits remain the critical bottleneck

Even with storage, value creation depends on whether power can move through the network when it is generated. Grid integration is described as both a constraint and a driver of returns because EMS—the transmission system operator—is managing increasing connection requests, particularly where grid capacity is limited. That dynamic can produce locational pricing effects as well as curtailment risk that must be reflected in project modelling.

Curtailment levels of about 5–15% in constrained nodes are flagged as plausible under high-penetration scenarios without grid upgrades. To mitigate this, parallel investment in transmission infrastructure is being planned—including substation upgrades, new 400 kV corridors and digital grid management systems—with cumulative CAPEX potentially exceeding €500–800 million by 2030.

Easier access to EU-linked markets could improve bankability

The EPS platform also carries implications beyond domestic supply security. As Serbia moves toward closer coupling with EU electricity markets, flexible renewable generation becomes more tradable—meaning storage-enabled operations could translate into additional revenue opportunities during peak price periods. Export potential into markets such as Hungary and Romania is cited as strengthening project bankability.

Financing structures are expected to evolve alongside this shift in how assets are used. While EPS remains the anchor entity, participation from international lenders—including export credit agencies and development banks—is anticipated to increase. Debt structures are likely to move toward 60–70% leverage, with DSCR targets around 1.3–1.5, reflecting both market risk considerations and changing regulatory frameworks.

[ [PRRS_LINK_1] ]

The transition still carries execution risks: procurement timelines can slip, grid bottlenecks can delay connections, and regulatory adjustments may require redesigns along the way. Even so, the direction described here points toward a structural change in how electricity will be produced, traded and valued—reducing exposure to carbon costs while improving flexibility—and positioning Serbia for European market dynamics through an investable hybrid platform anchored by EPS.