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Eastern Europe's BESS Moment: Turning 30+ GWh of Grid-Constrained Potential into Bankable Projects
Six markets, more than 30 GWh of visible opportunity—and no single route to bankability.
Central and Eastern Europe is entering a more demanding phase of its energy transition. Across Romania, Hungary, Croatia, Czechia, Poland and Bulgaria, renewable generation is expanding, public funding is mobilising investment, and electricity markets are placing greater value on flexibility.
Yet renewable deployment is often moving faster than transmission upgrades, connection procedures and market rules. Grid congestion, connection delays, midday price compression, steeper evening ramps and growing balancing needs are exposing a widening flexibility gap.
For developers, investors and EPC contractors, the critical question is no longer simply how much renewable capacity can be built, but how projects can be connected, controlled and monetised without creating unacceptable technical or commercial risk.
National targets, funded programmes, technical system requirements and visible project pipelines collectively indicate more than 30 GWh of medium-term storage opportunity across the six markets—although not all of this capacity is committed, financed or immediately deliverable.
Battery energy storage is therefore moving from an optional project enhancement to strategic power-system infrastructure.
On June 29, Romania's average day-ahead electricity price reached €224/MWh—the highest in Europe that day and nearly 2.5 times the levels recorded in neighbouring Bulgaria (€90/MWh) and Greece (€87/MWh). Hungary ranked second at €223/MWh. Extreme heat, rising electricity demand, reduced available generation and insufficient storage capacity all contributed to the price surge.
The event exposed a structural challenge: Romania can generate abundant low-cost renewable electricity during favourable periods, but lacks sufficient flexibility to shift that energy to evening peaks and periods of supply stress.
Operating BESS capacity reportedly increased from approximately 138 MW/269 MWh to almost 500 MW/914 MWh, with further large-scale projects entering operation in 2026.
Romania targets a renewable-energy share of 38.3% by 2030 and 44% by 2035, while strategic documents point to approximately 2 GW of BESS by 2030. Transelectrica estimates that integrating all planned renewable capacity could require 10–20 GWh of storage by the end of the decade.
Grid constraints are concentrated at specific connection points, particularly in renewable-rich regions where wind and solar deployment is outpacing local transmission development.
Lower short-circuit strength, constrained transmission corridors and limited reactive-power support can make voltage more sensitive to faults and rapid power changes.
For BESS projects, this creates stricter requirements for voltage control, reactive-power support, fault ride-through and stable PCS operation under low system strength. The actual point of connection must therefore be assessed early in project design.
Commercial opportunities are expanding across day-ahead and intraday trading, balancing energy, FCR, aFRR and mFRR.
The removal of network tariffs from electricity stored and subsequently returned to the grid has also reduced the previous double-charging burden, further improving the commercial environment for standalone and co-located BESS projects.
Recently, record-low water levels in the Danube forced the Paks nuclear power plant—the backbone of Hungary’s electricity system—to reduce output from near full capacity to just over 10%. Depending on river conditions, the plant may remain at this level for weeks.
The disruption is also likely to prompt the Hungarian government to further strengthen energy management, system flexibility and supply resilience.
Hungary's storage opportunity is closely linked to its rapid solar expansion.
Growing photovoltaic output is producing greater midday surpluses, lower or negative prices and steeper evening ramps. This creates demand for both time shifting and fast-response flexibility.
The European Commission approved a €1.1 billion Hungarian state-aid scheme targeting at least 800 MW/1,600 MWh of new electricity storage capacity. The programme sends a strong signal that storage is becoming an essential part of the country’s power-system strategy.
BESS projects can combine HUPX day-ahead and intraday trading with MAVIR ancillary services. For industrial users, solar self-consumption, peak shaving and backup resilience can provide additional value.
However, as more batteries enter the frequency-services market, projects relying on a single ancillary-service product may face revenue compression. Multi-market EMS optimisation, diversified revenue stacking and realistic assumptions about future market saturation will therefore become increasingly important.
Croatia briefly became a net electricity exporter in the first quarter of 2026. Total available electricity reached 5,227 GWh, exceeding domestic consumption of 5,096 GWh and creating a net export surplus of 131 GWh.
Renewables supplied 62.2% of available electricity. Solar generation increased by 50.7% year on year, while wind output fell by 12.8% due to weaker wind conditions. However, Croatia returned to net imports in March, with the trend continuing through April and May.
The rapid shift from surplus to imports highlights Croatia’s exposure to changing generation and demand conditions. As renewable capacity expands, storage can help shift surplus electricity to higher-demand periods and reduce reliance on imports when domestic generation falls.
Croatia remains an early-stage BESS market, with only around 11 MW of battery capacity currently identified. Its updated National Energy and Climate Plan foresees approximately 250 MW of battery storage by 2030.
However, the underlying grid requirement could be considerably larger. A national battery-deployment study identified 22 priority grid locations and estimated that Croatia could require up to approximately 1.7 GW of storage under a high-renewables scenario.
The 1.7 GW figure represents a technical system requirement rather than committed or operating capacity. Nevertheless, it illustrates the substantial gap between Croatia's current installed base and the flexibility its future electricity system may require.
Croatia has launched a €50 million RRP-funded scheme for business-led battery storage. The European Commission indicates that the programme could support approximately 100 MWh of capacity.
Potential revenue streams may include:
CROPEX day-ahead and intraday trading;
HOPS aFRR and mFRR balancing services;
renewable-plus-storage co-location;
peak-demand management and solar self-consumption;
grid support at constrained coastal and island locations.
The market is also moving toward larger projects. The EBRD is investing up to €16.8 million in Croatia’s first large-scale standalone BESS and virtual power plant project in Šibenik, which is expected to provide up to 60MW of flexible capacity.
Croatia may be starting from a small installed base, but rising solar generation, grid constraints, balancing-market reform and public funding point to a much larger long-term storage opportunity.
The LEX OZE III reform marks a structural shift in Czechia’s energy-storage market. It establishes a clearer framework for:
standalone BESS grid connection;
access to wholesale electricity trading and energy arbitrage;
participation in FCR, aFRR and mFRR markets, subject to ČEPS prequalification and technical requirements.
Czechia had approximately 2.3 GWh of battery storage by late 2025, but around 98% of the installed base in 2024 was located behind the meter.
With the market opening to standalone and utility-scale projects, Aurora Energy Research forecasts that Czechia’s battery-storage capacity could reach approximately 6 GWh by 2030.
According to Aurora Energy Research, Czechia is transitioning into a Central European flexibility hub driven by extreme price volatility and structural supply-demand imbalance.
Key market conditions include:
daily price spreads ~4x pre-crisis levels
gas-driven price floors 1.5x historical levels
increasing renewable intermittency
Phase I: 2026–2029 — Ancillary Market Driven Returns
In the early deployment phase, revenues are primarily driven by:
FCR and aFRR ancillary services
balancing and peak support services
Under current market conditions, a typical two-hour BESS operating at moderate cycling frequency can achieve:
IRR above 15%
payback period under five years
This phase is characterized by high margins driven by structural undersupply of flexibility.
Phase II: Post-2030 — Market Saturation and Arbitrage Dominance
As more than 1 GW of pipeline capacity connects to the grid, ancillary service markets are expected to gradually saturate.
This is likely to result in:
declining ancillary revenues (estimated ~30%+ compression risk)
increased competition in balancing markets
shift toward energy trading-led business models (day-ahead and intraday)
Between 2031 and 2040, energy arbitrage is expected to account for more than 80% of total battery revenues.
Longer-term value will increasingly depend on advanced system capabilities such as grid-forming capabilities, black start, and artificial inertia.
Poland's storage market is being shaped by the urgency of its energy transition. As one of Europe's most coal-dependent power systems and a key electricity hub in Central and Eastern Europe, the country is rapidly expanding renewable generation.
In June 2025, renewables supplied 44.1% of Poland’s electricity, exceeding coal at 43.7% for the first time. However, renewable deployment is advancing faster than the grid can accommodate. In the first half of 2026, approximately 1,174 GWh of renewable electricity was curtailed—44.7% more than in the same period a year earlier.
The combination of midday renewable surpluses, curtailment and constrained grid capacity is strengthening demand for energy shifting, balancing and grid-support services.
According to Modo Energy, Poland's BESS connection queue is divided almost evenly between standalone and co-located projects, with standalone capacity holding a narrow lead.
However, the balance is likely to shift toward co-location. The Grid Act (UC84) explicitly enables cable pooling, allowing renewable-generation and storage assets to share a grid connection. It also waives the grid-impact study requirement when adding an installation to an existing connection, provided the contracted connection capacity remains unchanged.
With new grid capacity increasingly scarce, co-location may become the most practical route for developers seeking to connect new BESS projects.
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According to Modo Energy, Grid access remains the main bottleneck for Poland’s BESS market. The connection queue exceeds 240 GW across renewables and storage, while available capacity at many substations is effectively exhausted.
Although PSE lists 397 BESS projects with connection conditions totalling approximately 82 GW, only 66 projects—around 11.5 GW—have secured signed connection agreements. This highlights the substantial gap between the headline pipeline and realistically deliverable capacity.
The Grid Act (UC84) introduces stricter collateral and milestone requirements to remove inactive projects from the queue. As a result, projects with secured grid access, mature permitting and credible delivery plans will hold a significant competitive advantage.
Bulgaria's largest co-located solar-storage project is advancing in the Yambol region. An operational 242 MWp solar plant and 65 MW/260 MWh BESS will be expanded with an additional 246 MW/512.5 MWh battery system.
The EBRD has approved financing of up to €30 million—approximately 42% of the project's €72 million total cost.
The transaction demonstrates growing institutional confidence in Bulgaria's utility-scale solar-storage market and is likely to attract further interest from developers and investors.
Bulgaria emerged as one of Europe's most dynamic battery-storage markets in 2025. The country connected approximately 2.7 GWh of new capacity—an increase of 1,061% year on year and the highest growth rate recorded in Europe.
This expansion placed Bulgaria fifth among Europe's annual BESS markets. It accounted for approximately 7% of all new European battery installations in 2025, marking the country's first breakthrough year for utility-scale storage.
The structure of this growth is equally important. Bulgaria's expansion has been driven predominantly by grid-scale projects, while distributed storage remains relatively underdeveloped due to the country's highly regulated electricity market.
EU-backed funding programmes have supported more than 10 GWh of utility-scale battery projects in Bulgaria. With comparatively near-term delivery deadlines, rapid deployment is expected to continue through 2026 and 2027.
Under SolarPower Europe's Medium Scenario, Bulgaria is expected to remain among Europe's five largest annual BESS markets in 2026, account for approximately 10% of European additions and surpass Italy in annual installations.
However, this accelerated build-out also creates risks:
grid-connection and commissioning delays;
increasing competition in balancing markets;
ancillary-service revenue compression;
dependence on one-off funding programmes;
potential market saturation after the initial deployment wave.
Bulgaria calculates network tariffs based on the difference between electricity withdrawn from and injected into the grid, reducing the burden compared with full double charging. Nevertheless, long-term bankability will depend on diversified revenue stacking, clearer market rules and reliable execution under compressed delivery schedules.
For developers and investors, Bulgaria offers one of Europe’s largest near-term utility-scale storage opportunities—but the next test is turning rapid, funding-led growth into sustainable project returns.
No single commercial model dominates Eastern Europe’s BESS market. Each country combines a different mix of ancillary services, wholesale trading, public funding, capacity payments and renewable integration.
| Market | Market & Grid Challenges | Core Commercial Model | Additional Value Streams |
| Romania | Renewable growth is outpacing local transmission capacity; some connection points face lower grid strength and stricter compliance requirements. | FCR, aFRR, mFRR and balancing energy | Day-ahead and intraday arbitrage; renewable co-location |
| Hungary | Rapid solar growth is creating midday surpluses, steeper evening ramps and greater demand for system flexibility. | Ancillary services and solar energy shifting | Wholesale trading; C&I self-consumption, peak shaving and resilience |
| Croatia | A small installed base, constrained coastal and island grids, and limited market liquidity create highly site-specific opportunities. | CROPEX trading and HOPS balancing services | Renewable co-location; C&I self-consumption and local grid support |
| Czechia | The market is transitioning from behind-the-meter systems to utility-scale storage, while ancillary-service revenues may compress as deployment grows. | ČEPS ancillary services | OTE day-ahead and intraday arbitrage; C&I optimisation |
| Poland | Severe grid congestion, limited connection capacity and a large speculative project queue restrict project delivery. | Capacity-market revenues combined with merchant trading | Cable pooling, renewable co-location, curtailment mitigation and ancillary services |
| Bulgaria | Rapid, funding-led deployment creates compressed delivery schedules and growing competition as large volumes enter operation. | Grant-supported utility-scale deployment | Balancing services, wholesale arbitrage and solar-plus-storage operation |
Three common trends are emerging across these six markets.
First, grid access is becoming as important as market potential. Poland’s connection queue, Romania’s local grid constraints and Croatia’s site-specific opportunities show that announced pipeline capacity does not necessarily translate into deliverable projects.
Second, revenue models are becoming more diversified. Ancillary services remain important in Romania, Hungary and Czechia, while Poland benefits from capacity-market revenues and Bulgaria is expanding through public funding. Across all six markets, wholesale arbitrage, co-location and renewable-energy shifting are becoming increasingly important.
Third, commercial and technical design can no longer be separated. Battery duration, PCS capabilities, EMS strategy and state-of-charge management must be configured around the accessible revenue streams and the actual conditions at the point of connection.
Across these markets, the difference between an attractive pipeline and a financeable project usually comes down to five questions.
A theoretical combination of capacity payments, arbitrage and ancillary services is not necessarily available to every project.
Developers must verify prequalification requirements, market-access rules, dispatch obligations and saturation risks. Revenue models should also account for degradation, availability and the opportunity cost of reserving capacity for different services.
A connection offer does not automatically provide unrestricted charging and discharging.
Import and export limits, network reinforcements, reactive-power requirements and dispatch constraints can materially affect both CAPEX and revenue. Existing connection rights and cable pooling may improve deliverability, particularly in Poland and renewable-rich markets.
Grants, capacity-market contracts and subsidised financing introduce milestones that directly affect bankability.
Developers must confirm whether permitting, procurement, construction, grid connection and commissioning can be completed within the required schedule. Failure to meet these obligations may result in lost subsidies, forfeited collateral or capacity-market penalties.
Grid compliance now extends beyond equipment certificates.
Projects may require RMS and EMT models, fault ride-through validation, reactive-power control, frequency response and stable operation under low system strength. Where required, grid-forming control, synthetic inertia and black-start functions must be supported by validated models and test evidence.
Responsibilities between the PCS supplier, battery supplier, system integrator and EPC contractor must be clearly defined.
Grid studies, controller coordination, commissioning, spare parts, remote diagnostics, cybersecurity and long-term service all influence whether a project reaches COD and performs as modelled. The lowest initial equipment price does not necessarily create the lowest lifecycle cost—or the most bankable asset.
Central and Eastern Europe offers substantial storage potential, but it is not a single market.
Romania combines growing balancing demand with demanding local grid conditions.
Hungary offers strong policy support but faces increasing ancillary-service competition.
Croatia presents a small installed base with significant site-specific flexibility needs.
Czechia is moving from behind-the-meter storage toward utility-scale participation.
Poland has the region’s largest visible pipeline, but grid access will determine how much of it is delivered. Bulgaria demonstrates how quickly public funding can accelerate deployment—and how rapidly execution and revenue risks can follow.
For developers, EPC contractors and investors, a regional strategy therefore cannot rely on one standard system configuration or one common revenue assumption.
Battery duration, PCS behaviour, EMS dispatch, grid models, compliance evidence and delivery capabilities must all be aligned with the market and point of connection.
The opportunity is not simply to deploy more storage. It is to turn constrained grid capacity, volatile renewable generation and evolving market rules into assets that can connect on time, perform as modelled and remain bankable throughout their operating lives.
This article opens the SINEXCEL Eastern Europe Energy Storage Series.
Next: How is SINEXCEL performing across these markets—and how much capacity has it deployed under diverse, real-world grid conditions?
Empowering Eastern Europe's Grid Resilience.
Coming soon.
Methodology note: Figures in this article are drawn from national authorities, European Commission and JRC documents, and reputable industry research. Because national sources apply different definitions and reporting dates, operating, awarded and pipeline capacity are identified separately wherever possible.
The figures in this article are drawn from national authorities, European Commission and JRC publications, transmission-system operators and reputable energy-industry research.
Because national sources apply different definitions and reporting dates, operating, awarded and pipeline capacity are identified separately wherever possible. Forecasts, technical system requirements and supported capacity should not be interpreted as operating capacity.
European Commission Joint Research Centre — Overview of Energy Storage Deployment in Europe European storage deployment, project status, technologies and national policy frameworks.
SolarPower Europe — European Battery Market Outlook 2026–2030 European battery-storage deployment trends and market outlook through 2030.
Energy Industry Review — Romania Enters the Battery Era Romania’s operating BESS capacity, project pipeline and market development.
European Commission — Romania’s Final Updated National Energy and Climate Plan Romania’s renewable-energy, storage and power-system development priorities.
Digi24 — Romania Records Europe’s Highest Day-Ahead Electricity Price Romania’s €224/MWh average day-ahead price on June 29, 2026, and comparison with Hungary, Bulgaria and Greece.
European Commission — €1.1 Billion Hungarian Electricity Storage Scheme State-aid programme supporting at least 800 MW/1,600 MWh of new electricity-storage capacity.
Hungarians curb power use as record low Danube waters trigger energy crunch
RES Croatia — National Study on Battery Storage in Croatia’s Electricity Grid Study of grid congestion, priority locations and optimal BESS deployment.
Balkan Green Energy News — Study Maps 22 Priority Locations for BESS in Croatia Croatia’s current BESS capacity, 2030 target and estimated system requirements.
EBRD — Croatia’s First Grid-Scale Battery Storage and Virtual Power Plant Development of a grid-connected BESS and VPP project with up to 60 MW of flexible capacity.
Renewables supplied over 62% of Croatia’s available electricity in Q1 2026 — Energy Portal / Renewable Energy Sources of Croatia (OIEH)
Croatia’s Revised National Energy and Climate Plan 2021–2030 — Croatian Ministry of Environmental Protection and Green Transition
Study maps 22 priority locations for BESS in Croatia — Balkan Green Energy News
Croatia has only 11 MW of battery capacity — Croatian Chamber of Economy / Balkan Green Energy News
Croatia allocates €50 million for business-sector BESS — Institute of Energy for South-East Europe
Croatia’s first grid-scale battery storage and virtual power plant — European Bank for Reconstruction and Development
European Commission – 2026 Country Report: Croatia
ESS News — Utility-Scale BESS to Drive Czechia’s Storage Market Current market structure, regulatory reform and Aurora’s 2030 storage outlook.
European Commission: €1.2 billion Polish electricity-storage scheme
Modo Energy: Poland’s BESS pipeline and grid-connection outlook
Baker McKenzie: UC84 grid-connection and cable-pooling reforms
Seetao: Poland's energy storage rise, Chinese enterprises win over 8GWhorders
Energy-Storage.news — Bulgaria Finalises Funding for Nearly 10 GWh of Storage First-round RESTORE awards covering 82 projects and 9,712.89 MWh of usable capacity.
IEA Policies Database — RESTORE: National Infrastructure for Electricity Storage Overview of Bulgaria’s EU-backed storage-support mechanism.
SolarPower Europe, European Battery Market Outlook 2026–2030, particularly pages 29, 34, 62, 66, 80 and 86–87
Seetao - Bulgaria's largest colocated energy storage project receives EBRD financing
