Southeast Europe’s nuclear market entered July 2026 with a split between the near-term commercial value of operating reactors and the uncertain economics of future construction. Existing plants are operating in a system shaped by hot-weather demand, constrained hydropower and higher natural-gas costs. New projects continue to move forward on political and technical fronts, but financing, construction risk, supply-chain exposure and long development timelines remain decisive.
The immediate question for markets is whether reactors are available during periods of highest regional electricity stress. In Southeast Europe, nuclear value is increasingly assessed through reliability and availability rather than installed megawatts alone. The ability to reduce reliance on more expensive marginal generation is also part of how nuclear output is reflected in system needs.
July 10 generation snapshot and intraday price swings
A regional generation snapshot for July 10 placed nuclear output at 5,579 MW. Hydropower was listed at 4,871 MW, while gas-fired generation stood at 4,521 MW. On the same day, Serbian electricity prices dropped to €20/MWh during a solar-rich afternoon before rising to €208.10/MWh in the evening.
Nuclear output does not track intraday price swings in the way hydro, gas or batteries can. Continuous generation instead reduces residual demand that flexible resources and often higher-cost units must cover. In smaller national systems, the return or loss of a single 700–1,000 MW reactor can affect import needs, cross-border flows and short-term price formation.
Romania’s Cernavodă Unit 1 restart and Krško output
Romania’s Cernavodă Unit 1 reconnected to the national grid on July 5 after completing planned maintenance. A July 7 regional market assessment linked part of an easing in Romanian supply conditions to the restoration of roughly 700 MW of nuclear capacity. Romania’s day-ahead price settled at €103.81/MWh that day, even though it still required about 596 MW of net imports.
The latest complete monthly figures from Krško were also described as strong. The jointly owned Slovenian-Croatian plant generated 495,096 MWh in June, about 1% above plan, with reported availability and capacity factors of 100%. Average net output was approximately 688 MW, shared between the two national systems.
Cernavodă refurbishment financing and planned outage window
Romania’s refurbishment programme is identified as the region’s most financeable nuclear segment. The European Investment Bank approved an €800 million loan for refurbishment of Cernavodă Unit 1 in July. The borrowing still requires approval from Nuclearelectrica shareholders before it can be contracted.
The loan is expected to complement a €540 million preliminary-phase loan signed in September 2025. The broader financing approach combines company equity with international financial institutions, export-credit agencies and commercial banks. The project has entered its second development phase covering permits, engineering and construction contracts, equipment procurement and financing.
Major refurbishment work, including reactor retubing, is scheduled for 2027–2030, with Unit 1 expected to resume operation in 2030. Nuclearelectrica estimates the refurbished unit would supply about 9% of Romania’s annual electricity between 2030 and 2060. The reactor has historically achieved a capacity factor above 90%.
The main operational complication is the refurbishment outage itself. Romania plans to replace Unit 1 output during the works through a mix of Unit 2 availability, renewable generation, imports, gas-fired capacity and storage. This approach is described as strengthening long-term energy security while tightening market conditions during execution.
Doicești SMR status after shareholder review
Romania’s SMR decision remains conditional despite being labelled a final investment decision. The Doicești project is described as less settled than terminology around its February approval suggested. Shareholders approved an FID for a planned 462 MW facility replacing part of a former 600 MW thermal-power site.
The approval included additional conditions followed by a six-month period focused on financial structuring and partnership development. In July, Nuclearelectrica shareholders rejected management’s proposal to reassess strategy by comparing additional SMR technologies and potential sites. Management said several conditions attached to the Doicești FID could not be met for reasons outside Nuclearelectrica and the project company’s control.
The company also highlighted higher technical, operational and financial complexity associated with first-of-a-kind technology. Progress is therefore described as depending on government support, agreement with the technology provider, capital structure, cost certainty and allocation of first-of-a-kind risk. These factors are presented as more important than the formal label attached to February’s decision.
Bulgaria fuel diversification at Kozloduy and AP1000 development
Bulgaria is described as diversifying nuclear fuel without yet achieving full independence across the supply chain. Kozloduy Unit 5 returned from annual maintenance on June 15 after receiving Westinghouse fuel assemblies for the third time. Bulgaria began a phased transition to alternative fuel for its VVER-1000 reactor fleet in 2024.
Bulgaria granted another sanctions derogation in June so Kozloduy could procure Russian-origin parts and components needed for operations. The two operating VVER-1000 units provide about 34% of Bulgarian electricity while much of their installed equipment remains based on Russian design and manufacturing. Unit 6 has also experienced two winter outages reportedly linked to difficulties sourcing replacement parts from a Russian supplier.
Bulgaria is simultaneously developing two Westinghouse AP1000 units at Kozloduy under an ongoing structuring process rather than financial close or a full notice to proceed . The official project company recorded July meetings with Westinghouse, Hyundai Engineering & Construction and US representatives. Indicative targets reported for Units 7 and 8 are 2035 and 2037.
Akkuyu commissioning tests; JEK2 spatial planning; Croatia legal framework
Akkuyu Unit 1 in Türkiye is identified as the closest major new reactor in the wider region to commercial operation. Construction work on the first unit has been completed and cold hydraulic testing began in June . Akkuyu comprises four VVER-1200 units totaling 4,800 MW, with Unit 1 targeted to begin supplying Turkey during 2026.
The project remains separated from sustained commercial operation by testing, regulatory approval, fuel loading and commissioning milestones . Slovenia’s JEK2 is at an earlier planning stage where preparation of a national spatial plan for a second Krško plant has started . Environmental assessments and protected-area evaluations are included, with spatial planning expected to conclude via government decree in autumn 2028.
Croatia created a broader legal framework for possible civilian nuclear energy development through a law published on May 27 . The law does not authorize an immediate plant; it sets institutional foundations for future decisions on policy, site selection, technology choice, financing and licensing. It also confirms continued Croatian support for the jointly owned Krško plant.
Danube low-flow episode highlights cooling-water constraints
The source material also points to cooling-water availability as an emerging constraint for summer nuclear planning. It cites Danube flow at Romania’s entry point falling to approximately 1,700 cubic metres per second, compared with a July average around 4,700 cubic metres per second. Romanian authorities controlled reservoir releases to maintain minimum water levels required to cool Cernavodă’s two reactors.
No reactor shutdown was reported in connection with the low-water event in July. River flows were expected to improve following rainfall . Cooling-water availability is therefore presented as needing assessment alongside fuel supply, maintenance schedules and grid risks during summer periods.
The river system supports hydropower generation, agriculture, navigation, ecosystems and municipal demand . Water allocation is therefore treated as a system-wide issue rather than only a plant-level concern . As climate conditions become more volatile, projects are expected to demonstrate resilient access to cooling water under stressed conditions.
Maturity gap between operating reactors and future megawatts
The near-term nuclear investment case in Southeast Europe is described as centred on safe operation and life extension of existing plants . These projects have clearer technical histories than first-of-a-kind SMRs or large greenfield reactors. They also rely on established grid infrastructure and have more visible routes to electricity revenues.
The material notes that governments continue advancing new capacity plans due to objectives including lower import exposure, reduced dependence on gas and firm low-carbon generation . It also states that political support alone has been shown as insufficient for delivery . Projects require credible construction budgets, state-aid approvals where applicable, long-term revenue arrangements, export-credit support, qualified supply chains and transparent cost-overrun risk allocation.
Nuclear value across the region is described as differentiating sharply by project type . Operating capacity cannot be valued the same way as reactors undergoing funded refurbishment or projects that remain primarily within planning documents . In Southeast Europe’s near term, the most valuable megawatts are those already generating or demonstrably financeable or supported by credible paths toward construction and operation .
