The implications for renewable developers in Serbia are no longer incremental—they are structural. A solar or wind project is shifting from being a price-taker in a volatile wholesale market to becoming a strategic node inside industrial export supply chains.
Until recently, most renewable projects in Serbia faced a familiar dilemma. Without fully developed long-term support schemes or deep corporate PPA markets, many assets were forced into merchant exposure, relying on SEEPEX day-ahead prices or short-term bilateral contracts. This created revenue volatility, with baseload prices fluctuating between €80/MWh and €130/MWh and intraday spreads often exceeding €30–70/MWh. For lenders, this translated into limited visibility, higher risk premiums and conservative leverage structures.
CBAM is beginning to change that equation fundamentally.
What is emerging is a new category of offtaker: CBAM-exposed industrial exporters, particularly in steel, cement, fertilisers and chemicals. These companies are no longer simply seeking electricity supply; they are seeking carbon-adjusted input structures that allow them to maintain competitiveness in EU markets.
For a renewable developer, this transforms the nature of the contract.
A long-term PPA with such an industrial buyer is no longer anchored solely in electricity demand. It is anchored in export continuity. The offtaker is not buying power as a discretionary cost input. It is securing a component of its ability to sell products into the EU without margin erosion from carbon costs.
This distinction materially strengthens the credit profile of the contract.
In traditional corporate PPAs, industrial offtakers often prioritised price flexibility, short tenors or optionality, reflecting uncertainty about future market conditions. In the CBAM-driven environment, the incentives shift. A steel or cement producer facing potential carbon costs of €20–40 per tonne of output linked to indirect emissions has a clear economic rationale to lock in renewable supply over longer periods.
This creates the foundation for 10–15 year PPAs, increasingly aligned with project finance requirements.
From a lender’s perspective, this changes the risk profile in several ways.
First, revenue visibility improves. Instead of relying on volatile merchant prices, the project secures a contracted revenue stream tied to an industrial offtaker with strong incentives to maintain the agreement. Even partial contracting—covering 50–70% of output—can significantly stabilise cash flows.
Second, counterparty risk is redefined. The industrial buyer is no longer simply exposed to electricity price fluctuations; it is exposed to carbon-adjusted export margins. Defaulting on a PPA could mean losing access to low-carbon electricity and facing higher CBAM costs at the border. This raises the economic cost of non-performance, effectively strengthening contract durability.
Third, price formation becomes more structured. Instead of purely fixed-price PPAs, hybrid models are emerging, combining fixed components with market-linked elements or floors and caps. These structures allow both parties to share upside from market volatility while maintaining downside protection.
In practical terms, this enables lenders to model cash flows with greater confidence. Debt sizing can move toward 65–75% of total CAPEX, with tenors extending to 12–15 years, compared to shorter tenors and lower leverage typically associated with merchant projects.
The bankability premium becomes even more visible when comparing two otherwise identical solar projects.
A merchant solar plant selling 100% into SEEPEX faces full exposure to price volatility, curtailment risk and market liquidity constraints. Its revenue profile may swing significantly year to year, depending on hydrology, regional demand and cross-border flows.
A contracted solar plant supplying an industrial exporter under a long-term PPA, by contrast, anchors a substantial portion of its revenue in a non-discretionary demand base, linked to industrial production and export activity. Even if wholesale prices fall, the industrial buyer still requires the electricity—and, crucially, the carbon attributes attached to it.
This creates a different type of asset.
It is no longer purely a generation asset exposed to market cycles. It becomes a quasi-infrastructure asset embedded in an industrial value chain, closer in risk profile to a regulated or contracted utility project.
For equity investors, this shift introduces a new layer of optionality.
On the downside, contracted revenues provide stability, supporting base-case returns in the range of 10–12% IRR. On the upside, uncontracted volumes—particularly when combined with battery storage—can capture intraday volatility, where spreads of €50–100/MWh are increasingly observed in Southeast Europe.
This dual structure—stable contracted base plus market-driven upside—is particularly attractive in a transitioning market like Serbia, where volatility is high but long-term decarbonisation signals are strengthening.
There is also a geographic dimension to this transformation.
Serbia sits at the intersection of EU and non-EU electricity markets, with increasing integration through interconnections and market coupling processes. As EU carbon pricing increasingly influences regional price formation, the value of CBAM-compliant electricity rises not only domestically but also in cross-border trading contexts.
Renewable projects positioned near key transmission corridors—such as those linking Serbia to Hungary, Croatia or Romania—gain additional strategic value. They can serve both domestic industrial demand and, potentially, export-oriented electricity flows aligned with EU carbon requirements.
Over time, this could lead to the emergence of industrial-renewable clusters, where large export-oriented facilities co-locate with or directly contract renewable generation assets. In such configurations, the boundary between energy production and industrial consumption begins to blur, with electricity procurement becoming an integrated part of industrial planning.
For developers, this implies a shift in business model.
Success will depend not only on securing land, permits and grid connections, but also on the ability to structure bankable, compliance-ready PPAs, backed by robust documentation of carbon intensity and aligned with EU methodologies. Developers who can offer this integrated package—electricity, data, certification and contractual flexibility—will be better positioned to attract both lenders and industrial offtakers.
In this emerging framework, the traditional distinction between merchant and contracted projects becomes less relevant. What matters is whether the project can position itself within a carbon-constrained industrial ecosystem, where electricity is valued not only for its energy content but for its role in enabling trade.
The result is a redefinition of bankability itself.
It is no longer driven solely by price forecasts and load factors. It is increasingly driven by the ability of the asset to support industrial competitiveness under carbon constraints.
For Serbia’s renewable sector, this represents a transition from peripheral generation to core economic infrastructure, embedded directly in the country’s export model and increasingly central to how value is created and preserved in a carbon-priced European market.
