South-East Europe’s power market is moving into a phase where physical access and asset control are becoming as important as day-ahead timing. Major trading houses are positioning themselves as hybrid operators, linking trading desks with control over transmission access, structured contracts and physical portfolios. For developers planning wind, solar and battery energy storage systems (BESS), this matters because the “route to value” is increasingly tied to who can secure pathways through constrained networks.
From arbitrage to asset-backed market access
Across the region’s main corridors, traditional congestion-driven arbitrage remains visible, but the balance of who captures returns is shifting. On the Serbia–Hungary border, annual traded volumes exceed 8–10 TWh, while available transfer capacity (ATC) allocations typically run at 600–1,000 MW against nominal capacity of 1,200–1,500 MW. Price spreads average €5–15/MWh under normal conditions and can widen to €40–60/MWh during winter stress or gas-driven volatility. Historically, traders monetised these spreads through day-ahead and intraday positioning supported by capacity acquired via yearly and monthly auctions.
What has changed is participation scale and structure. MET Group reported annual electricity trading volumes above 140 TWh across Europe and has expanded in South-East Europe using both trading desks and asset-backed strategies that include renewable portfolios and storage investments. Axpo, trading over 300 TWh annually, has followed a similar approach combining market operations with long-term capacity positioning and structured PPA portfolios. EFT, active across the Balkans, handles 10–15 TWh annually in SEE markets with deep exposure to cross-border flows involving Serbia, Bosnia and Montenegro.
Capacity rights become a planning input for developers
For engineering teams preparing grid connection studies and procurement packages, capacity rights are increasingly treated as a core variable in project bankability. Annual auctions on key interconnections—particularly Serbia–Hungary, Bulgaria–Greece and Romania–Hungary—clear at levels that reflect expected congestion rents. On the Serbia–Hungary corridor, yearly capacity prices can imply forward spreads of €8–20/MWh, effectively locking in part of arbitrage value ahead of dispatch outcomes. In practical terms for project execution readiness, this changes how developers model revenue stacks: transport constraints become measurable cash-flow components rather than background risk.
The Bulgaria–Greece interface illustrates why this is gaining attention from investors and contractors alike. Physical capacity is 1,200–1,500 MW with typical ATC of 700–1,200 MW, while annual flows exceed 10 TWh driven by Greek demand and LNG-linked pricing. Congestion revenues on this border have reached €150–200 million annually, making it one of Europe’s most valuable trading interfaces. Firms including PPC Trading, Axpo and MET actively position across the corridor by combining capacity rights with generation and balancing strategies to capture both spatial and temporal spreads.
BESS moves from utility-led buildouts to trader-backed portfolios
Battery storage development is also being pulled closer to market infrastructure logic. In Greece, more than 1 GW of battery capacity is under development or tendered, with participation from trading houses seeking to capture intraday spreads of €30–80/MWh. A typical 200 MWh battery system costing €80–120 million can generate annual revenues of €15–35 million through arbitrage and ancillary services depending on volatility conditions. These returns translate into equity IRRs of 12–18%, aligning closely with infrastructure investment benchmarks used in CAPEX planning.
In Serbia, storage is earlier in its development but moving in the same direction. Pilot projects combining 50–100 MW solar plants with 100–200 MWh storage are being structured with active involvement from traders such as GEN-I and EFT, which provide optimisation services and market access. For project developers coordinating EPC preparation—grid studies, dispatch modelling and ancillary service qualification—this pairing changes the technical focus from energy-only output to controllability across intraday windows. Storage becomes a tool for converting volatile spreads into bankable cash flows rather than relying solely on merchant exposure.
Long-term contracting expands beyond PPAs into structured delivery
Beyond spot optimisation, traders are expanding roles in long-term contracting frameworks that influence how renewable projects are financed and executed. Industrial PPAs linked to export-oriented sectors increasingly include trader participation in Serbia and Romania. Contracts with industrial consumers in steel, aluminium and chemicals sectors are being negotiated at €65–85/MWh with premiums of €5–10/MWh above merchant-adjusted prices reflecting carbon compliance requirements. Traders act as intermediaries aggregating supply from renewable projects and delivering structured products to offtakers.
In some structures they assume partial price risk—functioning as a hedge while retaining upside exposure—an arrangement that affects how credit support is designed during procurement and contract finalisation. For utilities and industrial stakeholders evaluating procurement frameworks, this also changes counterparty risk allocation across delivery schedules, imbalance responsibility and settlement mechanics tied to carbon-related premiums.
Transmission integration: HVDC as an operationally controllable channel
Transmission infrastructure remains central to how hybrid portfolios are engineered for predictable returns. The Montenegro–Italy HVDC link has capacity of 600 MW with annual flows of 4–5 TWh and has become a focal point for integration between trading strategies and physical access. Traders active in the region position across Italian and Balkan markets to capture spreads of €20–50/MWh using the cable as a controllable arbitrage channel. Annual congestion revenues are estimated at €70–150 million distributed among system operators and market participants able to access capacity through long-term rights or contractual arrangements.
This dynamic influences technical study priorities for developers preparing connection applications: modelling must reflect not only generation profiles but also how controllable transmission pathways affect dispatch feasibility under constraint scenarios. Platforms such as Electricity.Trade track these flows by providing visibility into capacity allocation, price spreads and congestion patterns—information that supports strategic targeting of investments in capacity rights, storage or generation aligned with persistent bottlenecks.
Investment planning implications for EPC readiness and grid modernization
The shift toward infrastructure-linked strategies alters risk profiles used in investor underwriting. Pure trading margins can be volatile because they depend on continuous repositioning, while infrastructure-backed revenues—whether from capacity rights, storage or long-term contracts—offer more stable cash flows. Hybrid portfolios combine predictable income supporting base returns with trading activity providing upside potential within operational limits defined by grid constraints.
Partnership structures are also evolving as private equity and infrastructure funds seek exposure to energy markets alongside trading houses that bring operational expertise and market access. These collaborations are particularly relevant for storage projects where capital requirements of €80–150 million per asset align with institutional thresholds and where revenue models depend on sophisticated optimisation strategies rather than energy-only assumptions.
Regulatory direction: coupling reduces some spreads while renewables add intraday volatility
Regulatory developments are shaping the pace of this transformation through changes in cross-border market design. Expansion of market coupling—including integration of Greece and Bulgaria into broader European frameworks—is expected to reduce some cross-border spreads. At the same time renewable penetration increases new forms of volatility, particularly within intraday markets where balancing needs rise alongside variability.
Traders are adapting by shifting focus from purely spatial arbitrage toward combined spatial-and-temporal strategies supported by physical assets such as batteries and renewable portfolios near key interconnections. For developers working through permitting steps, grid studies and EPC preparation schedules, trader-backed infrastructure creates additional routes to market beyond relying solely on utilities or bilateral PPAs—especially in constrained nodes where flexible operation can unlock value otherwise lost to curtailment.
Broader industry takeaway
The convergence between trading roles and infrastructure ownership is becoming more explicit across South-East Europe’s power system constraints: control over transmission access pathways increasingly determines how renewable generation and BESS deliver value over time. As long as transmission capacity remains uneven while renewables introduce variability, opportunities for optimisation will persist—but they are increasingly secured through asset control rather than accessed opportunistically through short-term timing alone.
For contractors preparing EPC scopes around dispatch performance guarantees, for utilities modernising grids under constraint pressure, for investors underwriting CAPEX linked to congestion exposure, and for industrial off-takers structuring long-term supply contracts, the implication is consistent: project economics now depend on integrating technical delivery capability with access to the pathways that shape price formation.