Electricity markets across South-East Europe are entering a phase in which pricing, contracting structures, and investment flows are increasingly shaped not by utilities or traders alone, but by industrial demand. The emergence of carbon-linked trade mechanisms, particularly the European Union’s Carbon Border Adjustment Mechanism, has transformed electricity from a variable operating cost into a strategic input tied directly to export competitiveness. In this environment, power purchase agreements are evolving from standard hedging instruments into complex financial structures that anchor renewable investment, reshape pricing curves, and influence how the transmission system itself is utilised.
The starting point for this transformation lies in the structural characteristics of the SEE grid. The region remains only partially integrated into the broader European market, with a mix of coupled and non-coupled zones. Serbia, positioned at the centre of this network, illustrates the complexity. The Subotica 400 kV substation, connected to Hungary, anchors access to Central European pricing, while southern nodes such as Niš and Vranje operate under tighter constraints, limiting export capacity toward Bulgaria and Greece. This creates a spatial pricing gradient in which identical electricity can carry materially different values depending on its point of injection into the grid.
Power purchase agreements increasingly reflect this reality. In northern Serbia and western Romania, where interconnection capacity is stronger and price convergence with Central Europe is more consistent, long-term PPAs are being negotiated in the range of €70–88/MWh. These contracts benefit from low curtailment risk—typically below 5%—and stable capture prices, allowing lenders to underwrite projects with leverage of 65–75% and DSCR profiles around 1.30–1.40x. The combination of predictable revenues and strong grid access positions these assets as low-risk within the regional context.
Further south, the economics become more complex. In central Serbia, Bosnia and Herzegovina, and inland Bulgaria, curtailment rises to 5–15%, and capture discounts deepen. Here, achievable PPA levels fall to €60–80/MWh, reflecting both lower realised prices and higher revenue volatility. Financing structures adjust accordingly, with lenders requiring stronger covenants, higher DSCR thresholds—often 1.35–1.50x—and lower leverage ratios in the range of 60–65%unless additional risk mitigation is introduced.
It is in the most constrained parts of the region—southern Serbia, North Macedonia, Albania, and certain areas of Greece—that the role of industrial offtakers becomes decisive. In these zones, curtailment can reach 15–35%, and capture price erosion pushes merchant revenues toward €45–70/MWh. Under such conditions, purely merchant projects struggle to achieve bankability. Yet this is precisely where industrial demand is beginning to reshape the landscape.
Energy-intensive industries, particularly in sectors such as steel, aluminium, and fertilisers, face increasing exposure to carbon pricing through CBAM. For these companies, access to low-carbon electricity is no longer optional; it is a prerequisite for maintaining access to European markets. As a result, they are entering long-term PPAs not only to stabilise costs but to secure the carbon credentials of their production processes. This creates a structural willingness to pay premiums of €5–15/MWh above merchant-adjusted prices, effectively raising the floor for renewable project revenues in otherwise disadvantaged locations.
In Serbia, this trend is beginning to intersect with the country’s broader industrial base. Facilities linked to metals processing and chemicals production are exploring direct procurement of renewable electricity, often in combination with guarantees of origin and carbon accounting frameworks aligned with EU standards. These contracts are typically structured over 10–15 year tenors, providing the long-term visibility required by lenders while retaining flexibility through partial indexation or volume adjustments linked to production levels.
The integration of such PPAs into project financing has a measurable impact on capital structure. By stabilising a portion of revenues, industrial offtake agreements improve DSCR profiles, allowing projects in Tier 2 and Tier 3 zones to achieve leverage levels closer to those seen in less constrained markets. A solar project in southern Serbia that might otherwise support only 55–60% debt can, with a well-structured industrial PPA, reach 65–70%, while maintaining DSCR above 1.30x. This shift is critical in a region where access to competitive financing remains a key determinant of project viability.
The Masdar–EPCG joint venture in Montenegro provides a forward-looking example of how these dynamics may evolve at scale. With a planned investment envelope of €3–4 billion, the platform is expected to develop a portfolio of renewable assets that will need to balance export opportunities via the Lastva–Pescara HVDC link with domestic demand and grid constraints. Industrial offtake, both within Montenegro and potentially across the wider region, is likely to play a central role in underpinning these investments. By anchoring a portion of output to long-term contracts, the joint venture can reduce exposure to volatile merchant markets while retaining upside through flexible volumes and cross-border optimisation.
The interaction between PPAs and storage further amplifies this effect. Hybrid projects combining generation with battery systems are increasingly able to offer shaped power products, aligning supply with industrial demand profiles. This capability commands a pricing premium, as it reduces the need for buyers to manage imbalance risk or procure additional balancing services. In practice, this can add €5–10/MWh to achievable PPA prices, particularly in markets where intraday volatility is pronounced.
The EPS solar-plus-storage pipeline in Serbia reflects this convergence of trends. By integrating battery systems into new projects, the utility is positioning its assets to deliver more stable and flexible output, making them more attractive to industrial buyers. A typical configuration—100 MW solar paired with 50 MW / 200 MWh storage, with total CAPEX of €140–180 million—can achieve equity IRRs of 10–13% when supported by a combination of PPA revenue and merchant optimisation. Without storage, the same project might struggle to exceed 7–9%, particularly in constrained nodes.
From a market perspective, the rise of industrial PPAs is altering the role of traditional participants. Utilities, which historically dominated long-term contracting, are increasingly complemented by direct agreements between generators and industrial consumers. Traders, meanwhile, are adapting by offering structuring services, managing residual merchant exposure, and optimising cross-border flows. Companies such as MET Group, Axpo, and EFT are positioning themselves as intermediaries not only in energy trading but in contract design and risk management.
This evolution is also influencing how transmission capacity is utilised. Industrial PPAs with cross-border elements—where electricity generated in one country is effectively consumed in another through financial arrangements—create new patterns of flow that interact with physical constraints. In some cases, this can exacerbate congestion; in others, it can help smooth imbalances by aligning production with demand across the network. The outcome depends on the interplay between contract structures and available interconnection capacity.
Looking ahead, the continued expansion of renewable capacity, combined with tightening carbon regulation, is likely to deepen these trends. Transmission investment, including projects such as the Trans-Balkan Corridor and internal reinforcements in Serbia and Montenegro, will gradually increase capacity, but not at a pace sufficient to eliminate congestion. As a result, the importance of structured contracting will continue to grow, providing a mechanism for managing both price risk and physical constraints.
For investors, the implications are clear. The value of a renewable project in SEE is no longer determined solely by its ability to generate electricity at low cost. It is determined by its ability to secure stable revenues in a system where prices vary by location and time, and where grid constraints introduce additional layers of complexity. Industrial PPAs offer one of the most effective tools for achieving this stability, particularly when combined with storage and access to interconnection capacity.
The SEE electricity market is therefore evolving into a system where infrastructure, contracts, and industrial demand are tightly interlinked. Transmission lines define where electricity can flow, contracts define how value is captured, and industrial demand defines the baseline against which all other dynamics operate. In this configuration, power purchase agreements are no longer peripheral instruments. They are central to the functioning of the market, shaping not only investment decisions but the distribution of value across the entire energy system.