By 2025, wind repowering emerged as one of the most quietly attractive investment opportunities in Southeast Europe. While public attention remained focused on new-build capacity, the region’s first generation of utility-scale wind farms—commissioned largely between 2010 and 2015—entered a phase where asset age, turbine efficiency and evolving market exposure began to materially affect performance. These assets are not obsolete. They are under-optimised. Repowering offers a way to reset their economics without re-entering the full permitting and grid-connection gauntlet that new projects increasingly face.
The structural logic of repowering in SEE is straightforward. Early wind projects were built with smaller turbines, lower hub heights and less sophisticated control systems. Typical turbine ratings ranged from 2.0 to 2.5 MW, hub heights were often below 100 metres, and rotor diameters were modest by current standards. Since then, turbine technology has advanced significantly. Modern onshore machines routinely exceed 4.5–6.0 MW, with hub heights of 120–160 metres and substantially larger swept areas. The energy yield improvement from these upgrades is not marginal. In SEE wind regimes, repowering can increase annual production by 15–30 percent, even when nameplate capacity remains unchanged.
Crucially, most of the hard work has already been done for these sites. Land rights are secured. Grid connections exist. Environmental and social acceptance is established. In many cases, grid permits allow for equal or higher capacity injections, subject to technical upgrades. Compared with greenfield development, repowering avoids years of uncertainty. This compression of risk is the core of the investment thesis.
Romania offers the clearest case study. The Dobrogea region hosts a dense concentration of wind farms commissioned in the early 2010s. These assets benefited from generous early support schemes and strong wind resources, but now operate with ageing equipment and rising maintenance costs. By 2025, typical OPEX for older Romanian wind farms had drifted toward €30–35 per MWh, driven by component replacements, gearbox issues and declining availability. Repowering resets this curve. New turbines reduce OPEX to €15–20 per MWh, while lifting output. Even where support schemes have expired, the combined effect restores competitive margins under merchant or PPA-backed operation.
Capital expenditure for repowering in SEE is materially lower than for new-build projects. Where foundations, roads and grid infrastructure can be reused, incremental CAPEX typically falls in a range of €400,000–600,000 per MW replaced. This compares with €1.0–1.3 million per MW for greenfield wind development. The capital efficiency is compelling. A repowered 100 MW wind farm may require €45–55 million in new capital, yet deliver energy output comparable to a much larger legacy installation.
The return profile reflects this asymmetry. In 2025 pricing conditions, repowered wind assets in SEE typically generate equity internal rates of return of 14–18 percent, assuming partial merchant exposure and conservative price assumptions. Where long-term PPAs are layered in, returns compress slightly but cash-flow stability improves dramatically. Payback periods on incremental capital often fall within 5–7 years, significantly shorter than new-build wind.
Greece illustrates a different but equally powerful repowering dynamic. Early wind projects in mainland Greece and on selected islands were built under restrictive technical standards. Grid congestion and curtailment have since become binding constraints. Repowering allows operators to replace many small turbines with fewer, larger machines, reducing wake losses and improving controllability. This not only increases output but reduces curtailment risk. In 2025, repowered Greek wind projects achieved effective capacity factors of 32–36 percent, compared with 25–28 percent for their original configurations.
Bulgaria sits somewhere in between. The country’s early wind fleet is smaller but similarly dated. Regulatory uncertainty slowed repowering decisions in the past, but merchant exposure and declining asset performance are forcing the issue. By 2025, repowering discussions increasingly centred on selective turbine replacement rather than full site rebuilds. Partial repowering—upgrading nacelles and control systems while retaining towers—offers output gains of 10–15 percent at even lower CAPEX, creating attractive incremental returns.
Serbia represents the next wave. Most Serbian wind capacity was commissioned after 2018, so full repowering is still years away. However, the country’s early wind farms will reach their first major refurbishment cycle in the early 2030s. Planning is already underway. Serbia’s clean permitting record, strong wind regimes and improving market integration suggest that repowering will become a core reinvestment strategy rather than an exceptional event. The advantage lies in foresight. Designing today’s wind farms with future repowering in mind reduces lifetime cost and extends asset relevance well beyond initial financial models.
From a system perspective, repowering also solves a grid problem. Rather than adding new connection points, repowering increases energy output from existing nodes. This is particularly valuable in SEE, where grid expansion lags generation growth. TSOs increasingly view repowering favourably because it delivers more energy without proportionally increasing congestion. In some jurisdictions, this has translated into faster approvals and reduced connection fees, further improving economics.
Financial markets have begun to recognise repowering as a distinct asset class. In 2025, transactions involving repowering-ready wind portfolios traded at premiums to both ageing assets and greenfield development pipelines. Buyers value the combination of reduced development risk, near-term cash-flow uplift and optionality around future PPAs or storage integration. Valuation uplifts of 0.5–1.0 EBITDA multiple relative to non-repowered peers are becoming common.
There are risks. Construction works must be carefully phased to minimise downtime. Legacy contracts, land leases and grid agreements require renegotiation. Turbine supply chains must align with site-specific constraints. However, these risks are operational rather than existential. They are manageable within disciplined project execution frameworks.
Strategically, wind repowering marks a maturation of the SEE renewable market. It signals a shift from expansion-at-all-costs to capital recycling and optimisation. Rather than chasing new megawatts, operators are extracting more value from what already exists. This mindset aligns with broader European trends but carries particular weight in SEE, where grid capacity, social acceptance and permitting bandwidth are finite.
By 2025, wind repowering in Southeast Europe had moved from concept to execution. It offers one of the highest return-on-capital opportunities available to renewable investors in the region, with lower risk than greenfield development and stronger upside than passive asset ownership. As early wind fleets age and market exposure increases, repowering will become not just attractive, but unavoidable.
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