Power purchase agreements in South-East Europe are being rewritten around one core reality: electricity is no longer a uniform commodity across a country or even within a bidding zone. The interaction between constrained 400 kV corridors, uneven renewable build-out and cross-border price formation has created implicit congestion zones, each with its own pricing logic. As a result, PPA structures are evolving from flat-price contracts into layered financial instruments that explicitly incorporate basis risk, delivery location and grid constraints.
The starting point for pricing remains the liquid reference markets. Across the region, forward baseload curves on HUPX (Hungary) and OPCOM (Romania) anchor expectations, typically in the €75–95/MWh range for 2026–2028 delivery. These benchmarks, however, represent system-wide averages that do not reflect nodal realities. A solar project connected near Subotica, with direct exposure to the Serbia–Hungary 400 kV corridor (1,200–1,500 MW capacity, 600–1,000 MW ATC), can effectively price its output close to these benchmarks, with minimal adjustments. Capture discounts remain limited to €2–5/MWh, and curtailment is below 5%, allowing PPAs to be structured at €70–85/MWh with strong bankability.
The same contract becomes materially different when applied to a project in central or southern Serbia. Around Kragujevac or Niš, where internal congestion and limited northbound transfer capacity constrain flows, capture discounts widen to €8–15/MWh, and curtailment assumptions reach 10–25%. A nominal €75/MWh PPA may translate into an effective realised price of €55–65/MWh, once both price and volume adjustments are applied. This divergence introduces basis risk—the difference between the reference price used in the contract and the actual price realised at the point of delivery.
To manage this risk, contracts are increasingly structured with zonal adjustments. Instead of a single fixed price, PPAs now incorporate location-based pricing components, often defined as a spread to a reference hub. For example, a contract might be priced as HUPX base minus €10/MWh, reflecting expected congestion and capture discounts for a given node. This approach aligns contract pricing with expected realised revenues, reducing the mismatch between financial assumptions and operational outcomes.
In Greece, where volatility is highest, PPA structures are even more complex. With day-ahead prices averaging €100–140/MWh but intraday spreads exceeding €60–100/MWh, fixed-price contracts expose both buyers and sellers to significant risk. As a result, hybrid structures are becoming standard. A portion of output—typically 50–70%—is contracted at a fixed or floor price in the €75–95/MWh range, while the remainder is sold on a merchant basis, often optimised through storage or trading strategies. This combination allows developers to secure a stable revenue base while retaining exposure to upside from volatility.
Industrial offtakers are central to this evolution. Companies such as Zijin Mining (Serbia), HBIS Group (Smederevo steel) and aluminium producers in Greece are increasingly entering long-term PPAs to manage carbon exposure and energy costs. These contracts often include premiums of €5–15/MWh above merchant-adjusted prices, reflecting the strategic importance of renewable electricity for export competitiveness under carbon constraints. Importantly, industrial buyers are willing to accept more complex pricing structures, including variable delivery profiles and index-linked pricing, in exchange for supply security.
Storage integration is reshaping PPA economics further. By shifting generation from low-price periods to peak demand hours, batteries reduce capture discounts and enhance realised prices. In practical terms, a 100 MW solar plant with a 200 MWh battery can increase its average realised price by €8–20/MWh, depending on market conditions. This uplift allows developers to offer more competitive PPA pricing while maintaining project returns. In Greece and Bulgaria, where volatility is highest, storage-backed PPAs are increasingly being negotiated at effective prices that reflect both base load and peak value.
Cross-border dynamics add another layer of complexity. Projects located near interconnections can arbitrage between markets, effectively pricing their output against multiple hubs. For example, assets near the Bulgaria–Greece corridor (1,200–1,500 MW capacity) can capture spreads of €20–50/MWh between the two markets, depending on conditions. PPAs for such projects may include clauses linked to multiple reference prices, allowing revenue to reflect cross-border optimisation rather than a single domestic benchmark.
The role of traders is expanding in this context. Firms such as MET Group, Axpo, GEN-I and EFT are acting as intermediaries, structuring PPAs that combine fixed-price components, market exposure and optimisation services. These “sleeved” agreements allow developers to access sophisticated pricing structures without directly managing market risk, while offtakers benefit from tailored contracts that align with their consumption profiles. Traders, in turn, monetise their ability to manage basis risk and optimise across markets.
Financial institutions are adapting their assessment frameworks accordingly. Lenders now evaluate PPAs not only on price and counterparty credit but also on their alignment with grid realities. Contracts that fail to account for location-specific risks are discounted in financial models, reducing debt capacity. Conversely, well-structured agreements that incorporate zonal pricing and flexibility can support higher leverage and more favourable terms. Debt margins for projects with robust PPAs can fall to 250–350 bps over Euribor, compared to 350–500 bps for projects with higher exposure to merchant risk.
Regulatory developments are gradually supporting this transition. Market coupling across Europe is improving price transparency and integration, while new frameworks for long-term contracts and guarantees of origin are facilitating PPA growth. However, the absence of explicit nodal pricing in most South-East European markets means that congestion effects remain implicit, requiring market participants to model and price them independently.
Data and analytics are becoming essential tools in this environment. Platforms such as Electricity.Trade provide insights into historical flows, ATC utilisation and price spreads, enabling more accurate modelling of basis risk. Developers and investors increasingly rely on such data to calibrate PPA pricing and assess the viability of different contract structures.
The evolution of PPA pricing reflects a broader shift in the electricity market. As renewable penetration increases and grid constraints become more visible, the value of electricity is increasingly determined by location and timing. Contracts must therefore capture these dimensions, moving beyond simple fixed-price structures to reflect the complexity of the system.
For developers, this means engaging with market design and grid dynamics from the earliest stages of project planning. Site selection, technology choice and contract structuring are now interdependent decisions, each influencing the others. For offtakers, it requires a deeper understanding of how electricity is priced and delivered, as well as a willingness to adopt more sophisticated contractual arrangements.
The result is a market where PPAs are no longer standardised products but tailored financial instruments, designed to balance risk and value across multiple dimensions. In South-East Europe, where congestion and volatility are defining features, this evolution is not optional. It is a necessary response to a system in which the physical realities of the grid are inseparable from the economics of electricity.