Southeast Europe’s nuclear market entered July 2026 with a clear divide between the immediate commercial value of operating reactors and the uncertain economics of future construction. Existing nuclear plants are benefiting from a power system characterized by hot-weather demand, constrained hydropower and higher natural-gas costs. 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 simply how much nuclear capacity could be operating in the 2030s. The more important question is whether today’s reactors are available when the regional electricity system is under the greatest pressure. In Southeast Europe, the value of nuclear power is increasingly being measured not only by installed megawatts, but by reliability, availability and the ability to reduce dependence on more expensive marginal generation.
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 hydropower and 4,521 MW of gas-fired generation. On the same day, Serbian electricity prices fell to €20/MWh during the solar-rich afternoon before rising to €208.10/MWh in the evening. Nuclear cannot follow that intraday price swing in the way hydro, gas or batteries can, but its continuous generation reduces the residual demand that those flexible and often more expensive resources must cover.
Romania provided a practical demonstration of this value. 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, approximately 1% above plan, with reported availability and capacity factors of 100%. That corresponded to 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. Instead, it reduces the size of the ramp that gas, hydropower, batteries and imports must cover. In relatively small national power systems, the return or loss of a single 700–1,000 MW reactor can materially alter import requirements, cross-border flows and short-term electricity prices.
Romania’s refurbishment programme is currently the region’s most financeable nuclear segment. Romania made the region’s most consequential nuclear-financing announcement of July when the European Investment Bank approved an €800 million loan for the refurbishment of Cernavodă Unit 1. The borrowing still requires approval from Nuclearelectrica shareholders before it can be contracted. It would complement a €540 million preliminary-phase loan signed in September 2025, with the broader financing strategy combining company equity, international financial institutions, export-credit agencies and commercial banks.
The project has already 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 that the refurbished unit would provide approximately 9% of Romania’s annual electricity supply between 2030 and 2060. The reactor has historically achieved a capacity factor above 90%.
From an investment perspective, life extension is currently the most mature nuclear opportunity in the region. It relies on an established site, existing grid infrastructure, an experienced workforce and an operating organization with decades of experience. It also avoids some—although not all—of the construction, licensing and technology risks associated with a completely new nuclear plant.
The main complication is the refurbishment outage itself. Romania must prepare to replace Unit 1’s output during the 2027–2030 works through a combination of Unit 2 availability, renewable generation, imports, gas-fired capacity and storage. A life-extension project can therefore strengthen long-term energy security while temporarily tightening the market during execution.
Romania’s SMR decision remains conditional despite the “final investment decision” label. The Doicești small modular reactor project is less settled than the terminology surrounding its February approval might suggest. Shareholders approved the FID for a planned 462 MW facility replacing part of a former 600 MW thermal-power site. The approval included additional conditions, after which the project entered a six-month period focused on 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 associated with first-of-a-kind technology.
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 allocation of first-of-a-kind risk. Those factors matter more than the formal label attached to the February decision.
Bulgaria is diversifying nuclear fuel, but not yet the entire nuclear supply chain. The country’s operating fleet 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, while much of their installed equipment remains based on Russian design and manufacturing. Unit 6 has also experienced two winter outages reportedly associated with difficulties sourcing replacement parts from a Russian supplier.
This distinction is significant for both investors and policymakers. Alternative fuel suppliers can reduce one strategic dependency, but long-lived reactors also require qualified components, engineering expertise, maintenance services and technical documentation. Replacing that broader ecosystem takes considerably 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. The project nevertheless remains in the development and structuring phase, rather than at financial close or a full construction notice to proceed.
The new-build pipeline contains projects with 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 operation. Akkuyu is therefore much closer to delivery than most other regional new-build projects, but the final transition from construction completion to reliable commercial generation still contains important technical and regulatory milestones.
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, after which 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; instead, 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 a single 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 timeline for actual electricity production.
Water is becoming an underappreciated nuclear risk. Nuclear generation is commonly discussed as protection against volatile fossil-fuel prices, but July demonstrated that reactors remain exposed to physical climate conditions and water availability. 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 cubic metres per second.
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 assessed alongside fuel, maintenance and grid risks in summer nuclear planning.
The same river system also supports hydropower, agriculture, navigation, ecosystems and municipal demand, making water allocation a system-wide issue rather than a plant-level concern. As climate conditions become more volatile, nuclear projects will increasingly need to demonstrate not only long-term fuel and grid security, but also resilient access to cooling water under stressed conditions.
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 continue to advance because governments want lower import exposure, reduced dependence on gas and firm low-carbon generation. July’s developments nevertheless show that political support alone is insufficient. Projects will require 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 different types of megawatts. Operating capacity, reactors undergoing funded refurbishment and projects that still exist primarily in planning documents cannot be valued in the same way. In Southeast Europe, the most valuable nuclear megawatts in the near term will be those that are already generating, demonstrably financeable or supported by a credible path to construction and operation.
