Nodal value is rewriting PPA economics across South-East Europe

Electricity pricing in South-East Europe highlights a shift in South-East Europe’s power market where long-term contracting is being pulled away from national averages and toward nodal economics. Even with countries operating as single bidding areas under zonal pricing, the physical network increasingly decides whether a renewable project can monetise the reference price—or whether it sells at a discount due to congestion, curtailment and limited cross-border access.

Zonal rules persist, but revenues are becoming location-specific

The region’s market structure remains rooted in zonal pricing: each country acts as a single bidding area for bids. Yet commercial outcomes are diverging by node. Projects connected to the same national system can record materially different price results depending on transmission constraints, curtailment patterns and their ability to access cross-border capacity. That divergence is now influencing not only how PPAs are priced, but also how lenders assess risk and whether deals remain bankable.

Why benchmarks don’t always translate into cash flows

A key tension lies between theoretical forward curves used in negotiations and what projects actually realise once dispatch meets network realities. In Hungary and Romania, baseload forward curves typically range between €75–95/MWh for the current horizon and continue to serve as reference points for PPA discussions. However, these benchmarks become meaningful for revenue only when generation can secure physical access to the core interconnection network.

When output sits in constrained nodes, effective capture prices begin to drift away from regional references—sometimes substantially—meaning that headline market levels do not reliably predict project income.

Northern Serbia shows tighter spreads; southern corridors face deeper discounts

In northern Serbia, the transmission system connects directly to Hungary via high-capacity 400 kV lines. Under those conditions, solar and wind projects can achieve realised prices close to the Hungarian curve, typically within a €2–8/MWh discount band. Curtailment levels are described as low (generally below 5%) alongside relatively stable export capacity. With these dynamics, long-term PPAs can be structured around €70–88/MWh, while lenders may support debt ratios of 65–75% with relatively tight pricing margins—where location effectively substitutes for additional contractual protection.

Moving toward central Serbia, internal bottlenecks reduce export capacity and push capture prices lower. Discounts relative to Hungarian benchmarks widen to €5–12/MWh, while curtailment risk rises to 5–15%. In these zones, PPAs typically settle between €60–80/MWh, reflecting both reduced expected revenues and higher volatility. Financing structures tend to become more conservative—often combining fixed-price contracts with merchant exposure—and lenders place greater weight on downside scenarios.

The report describes an even sharper divide in southern corridors across southern Serbia, North Macedonia and parts of Albania. Limited northbound transmission capacity plus high concentrations of solar generation create structural oversupply during daylight hours. Capture discounts can reach €15–30/MWh, while curtailment frequently exceeds 20%, particularly during summer months. Standalone renewables struggle to secure PPAs above €45–70/MWh; even then, achieving those levels often depends on strong counterparties or additional structuring elements. Debt financing becomes more constrained as leverage ratios fall to 50–60%, with pricing reflecting elevated risk.

The pattern repeats beyond Serbia: Romania, Bulgaria and Greece diverge by grid position

This nodal differentiation extends across the region rather than staying confined within one market. Romania is described as showing similar dynamics: western regions linked to Hungary tend to deliver higher capture prices than eastern zones closer to the Black Sea. In Bulgaria’s inland regions flows are characterised as relatively balanced, while areas nearer Greece experience more pronounced volatility and price divergence.

Greece itself reflects a distinct profile shaped by LNG-based marginal pricing alongside rapid solar expansion. Midday prices frequently collapse while evening peaks rise sharply—producing a system where average prices may stay high but solar capture depends heavily on timing and flexibility.

Curtailment risk becomes a contract variable through “capture ratio” thinking

The practical implication for developers and investors is that decision-making cannot rely solely on average market price levels. Instead, attention shifts toward 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, producing steadier revenues near benchmark levels.

• Similar assets placed in congested southern zones may see capture ratios drop to 0.70–0.85, reflecting both curtailment impacts and exposure to low-price periods.

• Wind projects generally fare better due to more diversified production profiles, with capture ratios ranging from 0.90 to 1.05, depending on location.

Storage changes what “location disadvantage” means for PPAs

The introduction of storage alters this equation by shifting generation from lower-price periods into higher-value hours for batteries paired with renewables or deployed alongside them. The report states that battery systems can raise solar capture ratios into the range of 0.95–1.15, helping neutralise much of the nodal disadvantage caused by congestion-driven discounts.

This has direct consequences for PPA structuring: projects that would otherwise require substantial price discounts may negotiate higher contract prices because variability falls and revenue predictability improves.

Industrial demand adds another pricing layer tied to compliance needs

The trend is also reinforced by industrial buyers seeking long-term renewable supply for cost stability and emissions-related compliance pressures tied particularly to carbon border adjustments (as described). These industrial PPAs introduce a premium element: counterparties may pay €5–15/MWh above merchant-adjusted levels in exchange for guaranteed supply.

Nodal effects still matter here—the premium can partially offset disadvantages from weaker grid positioning—but it becomes especially relevant when combined with storage or flexible generation profiles that improve delivery quality against market timing risks.

PPA designs evolve: shape, floors/upsides and hybrid contracting move up the agenda

The source also points out that contract architecture is changing alongside market behaviour:

• Simpler fixed-price deals indexed loosely off baseload proxies are giving way

• Toward arrangements incorporating shape (timing), location effects and flexibility

• An emphasis on mechanisms such as floor prices plus merchant upside

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• Volume adjustments linked to curtailment

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• Pricing formulas tied explicitly to specific reference markets

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