Southeast Europe’s nuclear market entered July 2026 with a clear divide between the commercial value of existing reactors and the uncertain economics of future construction. Operating nuclear plants are benefiting from a power system characterized by hot-weather demand, constrained hydropower and more expensive natural gas. New projects, meanwhile, continue to advance politically and technically, but financing, construction risk, supply-chain exposure and lengthy development schedules remain decisive.
The immediate market story is therefore not how much nuclear capacity may be operating in the 2030s. It is whether today’s reactors are available during the hours when the regional system is tight.
Reactor availability has immediate market value
A regional generation snapshot for July 10 placed nuclear output at 5,579 MW, compared with 4,871 MW of hydro and 4,521 MW of gas-fired generation. The same day, Serbian electricity fell to €20/MWh during the solar-rich afternoon before rising to €208.10/MWh in the evening. Nuclear could not follow that intraday swing in the way hydro, gas or batteries can, but its continuous production reduced the residual demand those more expensive flexible resources had to meet.
Romania supplied a practical demonstration. Cernavodă Unit 1 reconnected to the national grid on July 5 after completing its planned maintenance program. A July 7 regional market assessment attributed part of the subsequent easing in Romanian supply conditions to the restoration of approximately 700 MW of nuclear capacity. Romania’s day-ahead price settled at €103.81/MWh that day, although the country still required approximately 596 MW of net imports.
The latest complete monthly result from Krško was similarly strong. The jointly owned Slovenian-Croatian plant produced 495,096 MWh in June, about 1% above plan, with reported availability and capacity factors of 100%. That corresponded to an average net output of approximately 688 MW shared between the two national systems.
These examples illustrate nuclear’s present value proposition in Southeast Europe. Nuclear is not the resource that solves the evening ramp minute by minute. Rather, it reduces the size of the ramp that gas, hydro, batteries and imports must cover. In comparatively small national systems, the return or loss of a single 700–1,000 MW reactor can materially alter import requirements, cross-border flows and short-term prices.
Romania’s refurbishment program becomes the most financeable nuclear segment
Romania made the region’s most consequential nuclear-financing announcement of July. On July 15, the European Investment Bank’s board approved an €800 million loan for the refurbishment of Cernavodă Unit 1. The borrowing still requires Nuclearelectrica shareholder approval before it can be contracted. It would complement a €540 million preliminary-phase loan signed in September 2025, with the wider financing strategy combining company equity, international financial institutions, export-credit agencies and commercial banks.
The project is already in 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 that the refurbished unit would provide approximately 9% of Romania’s electricity supply annually between 2030 and 2060; the unit has historically achieved a capacity factor above 90%.
From an investment perspective, life extension is presently the most mature nuclear opportunity in the region. It uses an established site, grid connection, workforce and operating organization. It also avoids some—though not all—of the construction and licensing uncertainties associated with a completely new plant.
The complication is the refurbishment outage itself. Romania must prepare to replace Unit 1’s output during the 2027–2030 works through Unit 2 availability, renewable generation, imports, gas-fired capacity and storage. A life-extension project can therefore strengthen long-term security while temporarily tightening the market during execution.
Romania’s SMR decision remains conditional despite the “FID” label
Romania’s Doicești small modular reactor project is less settled than the phrase “final investment decision” might suggest. Shareholders approved the project’s FID in February for a planned 462 MW facility replacing part of a former 600 MW thermal-power site. The approval included additional conditions, and the project then entered a six-month period of financial structuring and partnership development.
In July, Nuclearelectrica shareholders rejected management’s proposal to reassess the initial strategy by comparing additional SMR technologies and potential sites. Management disclosed that several conditions attached to the Doicești FID could not be met for reasons outside the control of Nuclearelectrica and the project company. It also highlighted the higher technical, operational and financial complexity created by the project’s first-of-a-kind status.
The commercial interpretation is that Doicești remains an advanced development option, but not yet the equivalent of a fully financed, replication-ready construction project. Its progress will depend on government support, agreement with the technology provider, capital structure, cost certainty and the treatment of first-of-a-kind risk. Those variables matter more than the formal name attached to the February decision.
Bulgaria diversifies nuclear fuel, but not yet the entire supply chain
Bulgaria’s operating fleet also illustrates the difference between fuel diversification and full supply-chain independence. Kozloduy Unit 5 returned from annual maintenance on June 15 after receiving Westinghouse fuel assemblies for the third time. Bulgaria began its phased transition to alternative fuel for the VVER-1000 reactor in 2024.
However, Bulgaria granted another sanctions derogation in June so that Kozloduy could procure necessary Russian-origin parts and components. The two operating VVER-1000 units provide approximately 34% of Bulgarian electricity, and much of their installed equipment remains of Russian design and manufacture. Unit 6 experienced two winter outages reportedly associated with sourcing replacement parts from a Russian supplier.
This is a significant distinction for investors and policymakers. Alternative fuel suppliers can reduce one strategic dependency, but long-lived reactors also require qualified components, engineering knowledge, maintenance services and documentation. Replacing that ecosystem takes longer than changing fuel contracts.
Bulgaria is simultaneously developing two Westinghouse AP1000 units at Kozloduy. The official project company recorded July meetings with Westinghouse, Hyundai Engineering & Construction and US representatives, while indicative targets reported for Units 7 and 8 are 2035 and 2037. Yet the project remains in the development and structuring phase rather than at financial close or full construction notice to proceed.
The new-build pipeline has several very different levels of maturity
Türkiye’s Akkuyu Unit 1 is 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 under a Russian build-own-operate model, with Unit 1 targeted to begin supplying the Turkish system during 2026. Testing, regulatory approval, fuel loading and commissioning still separate the project from sustained commercial output.
Slovenia is at a much earlier planning stage with JEK2. The government initiated preparation of the national spatial plan for a second nuclear plant at Krško, including environmental and protected-area assessments. The spatial-planning procedure is expected to conclude with a government decree in autumn 2028, before the project can move through later investment, technology and financing decisions.
Croatia has meanwhile created a broader legal framework for the possible development of civilian nuclear energy. The law, published on May 27, does not authorize an immediate plant; it establishes the institutional basis for future policy, site, technology, financing and licensing decisions. It also confirms continued Croatian support for the jointly owned Krško plant.
These projects should not be combined into one headline capacity pipeline. Akkuyu is undergoing commissioning tests; Cernavodă Unit 1 has an advanced refurbishment and financing plan; Bulgaria’s AP1000 project is being structured; JEK2 is entering spatial planning; and Croatia has established policy optionality. Each represents a different probability and timing of actual electricity production.
Water is nuclear’s underappreciated July risk
Nuclear generation is commonly discussed as protection against volatile fossil-fuel prices, but July demonstrated that it is not isolated from physical climate conditions. The Danube’s flow at Romania’s entry point fell to approximately 1,700 cubic metres per second, compared with a July average of around 4,700. Romanian authorities controlled reservoir releases to maintain the minimum water levels required to cool Cernavodă’s two reactors.
There was no reported reactor shutdown associated with the July low-water event, and river flows were expected to improve following rainfall. Nevertheless, cooling-water availability must now be included alongside fuel, maintenance and grid risk in summer nuclear assessments. The same river system also serves hydropower, agriculture, navigation, ecosystems and municipal demand, making water allocation a system-wide issue rather than a plant-level concern.
Existing nuclear assets will command the greatest near-term value
The strongest nuclear investment case in Southeast Europe remains the safe operation and life extension of existing plants. These projects have clearer technical histories, established grid infrastructure and a more visible route to electricity revenues than first-of-a-kind SMRs or large greenfield reactors.
New capacity will still advance because governments want lower import exposure, less dependence on gas and firm low-carbon generation. But July’s developments show that policy support alone is insufficient. Projects will need credible construction budgets, state-aid approval where applicable, long-term revenue arrangements, export-credit support, qualified supply chains and transparent allocation of cost-overrun risk.
Nuclear’s regional value is rising, but the market will differentiate sharply between megawatts that are operating, megawatts undergoing funded refurbishment and megawatts that still exist primarily in planning documents.
