The European integration of electricity markets rests on the principle that power should flow from low-price to high-price zones, up to the limit of available transmission capacity. While European electricity market integration has progressed significantly under the EU Target Model, persistent price divergence and intermittent inefficiencies in cross-border flows suggest that full market coupling has not yet been fully achieved in practice. When this does not occur, measurable economic losses arise — referred to in the literature as foregone benefits.
In the following, the Net-Zero Lab quantifies such losses for Bulgaria’s two key cross-border interconnections with Romania (BG–RO) and Greece (BG–GR), drawing on hourly observations for 2025. The analysis also addresses a question of broader policy relevance: are imports driven by a structural deficit in domestic generation, or by price arbitrage — that is, by temporary price differentials reflecting differences in the generation mix?
- Price Environment
The average day-ahead price for 2025 is EUR 106.9/MWh in Bulgaria, EUR 103.6/MWh in Greece, and EUR 108.2/MWh in Romania. Despite similar averages, intra-day and seasonal variation is substantial: peak prices reach EUR 603/MWh (BG, RO) while minima fall to −EUR 100/MWh — a direct consequence of the growing share of solar and wind generation.
| Market | Avg. Price (EUR/MWh) | Min. | Max. | Std. Dev. |
| Bulgaria | 106.9 | −100.6 | 603.3 | ~73 |
| Greece | 103.6 | −50.0 | 478.9 | ~71 |
| Romania | 108.2 | −100.6 | 603.3 | ~73 |
Bulgaria and Romania hit their shared peak simultaneously on the same January evening — a classic winter demand spike, likely with gas/thermal generation setting the marginal price. Greece’s peak comes later in October, in the evening hours when solar drops off completely. The negative minimums on 1 May are particularly striking — they reflect oversupply from renewables (the holiday reduces demand while solar/wind production continues), forcing generators to pay to offload power. Greece’s minimum is less extreme (−50 vs −100.63), suggesting its grid absorbed or exported more of the surplus that afternoon.
In 16.5% of hours (1,445 h), the Greek price is lower than the Bulgarian price — primarily during periods of high solar generation. Romanian prices are lower than Bulgarian prices in 1% of hours. In only 0.1% of cases (13 h) does Bulgaria offer the lowest price in the region.
- Cross-Border Flow Patterns and Market Dynamics
On the BG–GR axis, imports were recorded in 4,624 hours (1,095 GWh) and exports in 4,125 hours (941 GWh). On the BG–RO axis, flows are more intensive: imports in 4,224 hours (2,041 GWh) and exports in 4,530 hours (2,373 GWh). The bidirectional nature of flows is indicative of a functioning market mechanism rather than a unilateral import dependency.
Electricity flows from Greece to Bulgaria exhibit strong seasonal and intra-day structure. Imports into Bulgaria are concentrated in the late autumn and winter months, particularly in November, December, and March, and occur predominantly during the daytime window between 10:00 and 15:00. This period coincides with higher shares of renewable energy generation in Greece, primarily from solar, wind, and hydro, which contributes to lower wholesale electricity prices. During the summer months, imports occur less frequently and are shift toward evening hours (19:00–22:00), suggesting a swing in the timing of price differentials, potentially linked to changes in renewable generation profiles and demand patterns.
A representative example illustrates these dynamics clearly. On 20 November, Bulgaria imported electricity from Greece throughout the day, as Bulgarian prices remained consistently higher. Peak imports occurred around midday, coinciding with renewable energy shares exceeding 80% in Greece1. During these hours, low marginal costs resulted in near-zero prices, while Bulgaria experienced tighter supply conditions due to reduced nuclear generation and comparatively lower renewable penetration. The Greek price profile on that day showed strong intra-day variability, ranging from near-zero values during peak renewable production to levels above 155 EUR/MWh in the evening, when thermal generation became dominant. This pattern is consistent with the “duck curve” effect and highlights the increasing role of variable renewable energy in shaping cross-border electricity flows.
Price Arbitrage or Supply Deficit? Diagnosing Imports
Central analytical question: When Bulgaria imports electricity from Greece, is this because domestic capacity is insufficient, or because it is economically advantageous to do so?
The data provide strong support for the price arbitrage hypothesis:
- Of the 4,624 hours during which imports from Greece are observed, 68.4% occur under fully coupled (converged) price conditions — meaning imports continue even after the price differential is eliminated, owing to the physical inertia of flows.
- In 29.3% of import hours (1,354 h), the Bulgarian price exceeds the Greek price — with an average differential of EUR 29.8/MWh, at a mean Bulgarian price of EUR 120.8/MWh versus EUR 91.0/MWh in Greece.
- Average capacity utilisation during price-driven imports is only 36.6%, with a median of 37.8%. Only 11 hours (0.8%) record utilisation above 80%.
- During hours with the highest Bulgarian prices (top decile, >EUR 172/MWh), average capacity utilisation is 23.1% — below the mean for price-driven import hours. Greece is cheaper in only 209 of these 876 hours.
Low capacity utilisation even in the presence of significant price differentials is the key diagnostic finding: if imports reflected a capacity deficit, system operators would be expected to maximise available transmission capacity. The observed behaviour is consistent with market-based arbitrage operating under operational constraints.
Seasonal Structure of Price Differentials
Greece is cheaper than Bulgaria primarily during periods of high RES generation:
| Period | Avg. BG Price | Avg. GR Price | BG–GR Differential | Interpretation |
| November | 121.5 | 106.5 | −15.1 | High solar/wind share in GR |
| December | 117.3 | 110.0 | −7.3 | Moderate RES share |
| October | 121.7 | 112.3 | −9.5 | Autumn RES profile |
| August | 75.8 | 73.2 | −2.7 | Summer solar peak |
| March | 104.4 | 105.9 | +1.5 | GR more expensive — BG exports |
| April | 85.0 | 89.1 | +4.1 | GR more expensive — BG exports |
This pattern is fully consistent with the so-called duck curve effect: midday hours of high solar output in Greece generate near-zero or negative prices, while the evening demand peak — when solar generation is absent — causes prices to spike sharply. Bulgarian imports follow this logic, concentrated in the 08:00–14:00 window, with an additional evening window (19:00–22:00) observed during summer months
- Foregone Benefits by Interconnection Corridor
Bulgaria–Romania Interconnection
The interconnection between Bulgaria and Romania exhibits a high degree of integration, with only 443 hours in 2025 characterized by non-coupled but economically efficient conditions. Despite strong integration, measurable foregone benefits arise due to incomplete utilization of available transmission capacity. Total welfare losses amount to approximately 10.55 million EUR, of which 9.77 million EUR is associated with missed export opportunities from Bulgaria to Romania. These inefficiencies exhibit systematic intra-day and seasonal patterns, concentrated in winter daytime hours (between 09:00 and 13:00) and summer peak demand periods (in the morning (07:00–10:00) and evening (20:00–21:00). Notably, these periods often coincide with either import-related foregone benefits or fully coupled conditions on the BG–GR interconnection. This suggests that wholesale electricity prices in Greece are frequently lower than or equal to those in Bulgaria during these intervals, while prices in Romania remain higher. From an economic perspective, this configuration implies that the efficient outcome would involve transit flows from Greece to Romania via Bulgaria. However, in 18 of these instances, the BG–GR interconnection exhibits outright inefficiency, with electricity flowing from Bulgaria to Greece despite higher wholesale prices.
| EUR 10.55m total foregone benefits — BG–RO | EUR 0.78m foregone imports into Bulgaria | EUR 9.77m foregone exports from Bulgaria |
Bulgaria–Greece Interconnection
Overall, 85 hours can be classified as inefficient for the BG–GR interconnector, meaning that cross-border flows do not follow the direction implied by relative prices. In these instances, electricity is either not transmitted when economically justified or flows in the opposite direction of price signals. The total foregone benefit associated with the Bulgaria–Greece interconnection amounts to approximately 29.95 million EUR for 2025, significantly exceeding the corresponding value for the Bulgaria–Romania border. Of this amount, approximately 804 thousand EUR is directly attributable to the 85 inefficient hours in which flows contradict price signals. These inefficiencies are concentrated primarily in the summer and early autumn months – July through October – and occur predominantly during daytime hours (08:00–14:00). The largest share of welfare losses – around 792.9 thousand EUR – is associated with missed import opportunities into Bulgaria. This indicates that Bulgarian consumers are more affected by inefficiencies on this interconnector, as they are unable to fully access lower-cost electricity available in Greece during these periods. Substantial unused transmission capacity is also observed. The cumulative unused capacity amounts to approximately 7.59 million MWh in the direction from Greece to Bulgaria and 9.39 million MWh from Bulgaria to Greece.
| EUR 29.95m total foregone benefits — BG–GR | EUR 21.97m foregone imports into Bulgaria | EUR 7.98m foregone exports from Bulgaria |
- Key Insights & Policy Implications
- Transmission Management versus Infrastructure Expansion
The low-capacity utilisation observed in the presence of available price differentials indicates that infrastructure expansion is not the binding constraint. Capacity allocation mechanisms and coordination between transmission system operators (TSOs) offer a more immediate lever for efficiency gains.
- RES Integration and Cross-Border Flexibility
The growing amplitude of intra-day price volatility, driven by the expansion of RES capacity across the region, will increase the value of effective interconnection management. Regions with high RES shares (Greece) and those with a more conventional generation mix (Bulgaria) exhibit complementary supply-and-demand profiles — a potential that requires flexible cross-border infrastructure to be realized
- Bulgaria as a Transit Corridor
The data corroborate Bulgaria’s role as a potential transit node between Greek RES generation and Romanian and Central European demand. Coordinated improvements to the efficiency of BG–GR and BG–RO could generate regional welfare gains extending beyond the bilateral level.
- Distributional Effects and Social Equity
The asymmetry in the distribution of foregone benefits — with 73% of BG–GR losses associated with missed access to cheaper imports — implies that inefficiencies are borne disproportionately by end consumers in Bulgaria through higher market prices. In the context of the social impacts of the energy transition, this dimension warrants explicit attention in market design reforms.
- Methodological Note:
The analysis covers 8,760 hourly observations for the period 1 January to 31 December 2025. Data were extracted from the ENTSO-E Transparency Platform and comprise day-ahead market prices, physical cross-border flows, and forecast transfer capacities for both interconnections.
Foregone benefits are calculated as the product of the absolute price differential between interconnected markets and the unused transmission capacity in the economically efficient direction. Hours are classified into three categories:
- Coupled — price differentials are zero (full market integration for the hour in question);
- Efficient — flows follow the direction implied by price signals;
- Inefficient — flows contradict price signals.
The measure constitutes an upper bound on potential losses. Real operational constraints — internal network congestion, system security requirements, loop flows, and capacity allocation mechanisms (CACM/FCA) — are not incorporated in the model and would reduce the practically achievable efficiency improvement potential.
The diagnosis of price arbitrage versus supply deficit is based on analysis of capacity utilisation during price-driven import hours, the distribution of flows relative to price differentials, and the seasonal and intra-day structures of imports and price spreads. The analysis was conducted in Python; visualisations were produced in Python and Canva.
Authors: PhD Candidate Lyubimka Georgieva & Dr. Mariya Trifonova