Electricity pricing in South-East Europe has entered a phase where geography is no longer a background variable but the central determinant of value. The formal structure of the market still relies on zonal pricing, with countries acting as single bidding areas, yet the commercial reality is increasingly nodal. Projects connected to the same national system can experience materially different price outcomes, driven by transmission constraints, curtailment patterns and access to cross-border capacity. This divergence is now shaping the structure, pricing and bankability of power purchase agreements across the region.
At the core of this shift lies the gap between theoretical and realised prices. Forward curves in Hungary and Romania—typically ranging between €75–95/MWh for baseload delivery in the current horizon—continue to serve as reference points for PPA negotiations. However, these benchmarks only translate into actual project revenues when physical access to the core interconnection network is secured. As soon as generation is located in a constrained node, the effective capture price begins to diverge from the regional benchmark, often significantly.
In northern Serbia, where the transmission system connects directly to Hungary through high-capacity 400 kV lines, solar and wind projects can achieve realised prices close to the Hungarian curve, typically within a €2–8/MWh discount range. Curtailment levels remain low, generally below 5%, and the system benefits from relatively stable export capacity. Under these conditions, long-term PPAs can be structured in the range of €70–88/MWh, with lenders willing to support debt ratios of 65–75% and relatively tight pricing margins. The project’s location effectively substitutes for additional contractual protection.
Moving south within the same country, the economics shift. In central Serbia, where flows begin to encounter internal bottlenecks and reduced export capacity, capture prices fall. Discounts relative to Hungarian benchmarks widen to €5–12/MWh, and curtailment risk increases to 5–15%. PPAs in these zones typically settle between €60–80/MWh, reflecting both lower expected revenues and higher volatility. Financing structures become more conservative, often requiring a mix of fixed-price contracts and merchant exposure, with lenders placing greater emphasis on downside scenarios.
The divergence becomes more pronounced in southern corridors, including southern Serbia, North Macedonia and parts of Albania. Here, limited northbound transmission capacity and high concentrations of solar generation create structural oversupply during daylight hours. Capture discounts can reach €15–30/MWh, and curtailment levels frequently exceed 20%, particularly in summer months. In such environments, standalone renewable projects struggle to secure PPAs above €45–70/MWh, and even these levels often depend on the presence of strong counterparties or additional structuring elements. Debt financing becomes constrained, with leverage ratios falling to 50–60% and pricing reflecting elevated risk.
This nodal differentiation is not limited to Serbia. Romania exhibits similar patterns, with western regions connected to Hungary achieving higher capture prices than eastern zones closer to the Black Sea. Bulgaria’s inland regions benefit from relatively balanced flows, while areas closer to Greece experience more pronounced volatility and price divergence. In Greece itself, the combination of LNG-based marginal pricing and rapid solar expansion produces a distinct profile, with midday prices frequently collapsing and evening peaks reaching elevated levels. The result is a system where average prices remain high, but capture prices for solar projects are heavily dependent on timing and flexibility.
For developers and investors, the key variable is no longer the average market price but the capture ratio—the proportion of the reference price that a project actually realises. Solar projects in well-connected northern nodes may achieve capture ratios of 0.90–0.95, translating into stable revenues close to the benchmark. In contrast, similar assets in congested southern zones may see capture ratios fall to 0.70–0.85, reflecting both curtailment and exposure to low-price periods. Wind projects, with more diversified production profiles, generally perform better, with capture ratios ranging from 0.90 to 1.05, depending on location.
The introduction of storage fundamentally alters this equation. By shifting generation from low-price periods to higher-value hours, battery systems can increase capture ratios for solar projects to 0.95–1.15, effectively neutralising a large portion of the nodal disadvantage. This has direct implications for PPA structuring. Projects that would otherwise require significant price discounts can negotiate higher contract prices, as the variability of output is reduced and revenue predictability improves.
Industrial demand is reinforcing this trend. Energy-intensive sectors, particularly those exposed to carbon border adjustments, are increasingly seeking long-term renewable supply to secure both cost stability and compliance with emissions requirements. These industrial PPAs introduce a premium element into pricing, with counterparties willing to pay €5–15/MWh above merchant-adjusted levels in exchange for guaranteed supply. In nodal terms, this can partially offset the disadvantages of weaker grid positioning, particularly when combined with storage or flexible generation profiles.
The structure of PPAs themselves is evolving in response. Traditional fixed-price contracts, indexed loosely to baseload benchmarks, are giving way to more sophisticated arrangements that incorporate shape, location and flexibility. Contracts may include floor prices combined with merchant upside, volume adjustments linked to curtailment, or pricing formulas tied to specific reference markets. In some cases, developers and offtakers are entering into hybrid arrangements where a portion of output is sold under long-term contracts while the remainder is optimised through trading strategies.
Market participants active on platforms such as Electricity.Trade are increasingly focused on these nuances, analysing not just headline prices but the underlying drivers of capture and volatility. For traders, the ability to forecast nodal spreads and identify periods of divergence is becoming as important as traditional arbitrage strategies. For developers, the same insights inform site selection, technology choice and financing structures.
Transmission investment will gradually reshape this landscape, but not eliminate it. Projects such as the Trans-Balkan corridor and internal grid reinforcements in Serbia, with combined investments exceeding €500 million, are expected to increase transfer capacity and reduce some bottlenecks. However, experience across Europe suggests that new capacity often leads to new patterns of flow rather than complete convergence. As renewable penetration increases, variability itself becomes a source of congestion, particularly when generation is concentrated in specific regions.
This dynamic ensures that nodal economics will remain central to PPA pricing for the foreseeable future. Developers who treat location as a secondary consideration risk mispricing their assets and overestimating returns. Conversely, those who integrate grid analysis into project development can identify opportunities where structural advantages translate into higher and more stable revenues.
The implications extend beyond individual projects. As nodal differentiation becomes more pronounced, it will influence the allocation of capital across the region. Investors are likely to favour assets in well-connected nodes, where revenue predictability supports higher leverage and lower financing costs. At the same time, constrained regions may attract capital for complementary technologies such as storage or flexible generation, which can monetise volatility and alleviate local imbalances.
In this environment, the distinction between market and infrastructure begins to blur. Transmission constraints shape prices, prices shape contracts, and contracts determine the flow of capital. The SEE electricity market is therefore evolving into a system where value is defined not by national boundaries but by position within the grid. Understanding that position—quantitatively and strategically—has become a prerequisite for participation.
As the region continues to integrate with broader European markets, the tension between convergence and local differentiation will persist. Full alignment would require a level of transmission density and operational coordination that remains years away. Until then, the geography of the grid will continue to define the economics of power, and PPA pricing will remain inseparable from the physical realities of the network.