As renewable build-outs accelerate across Central and South-East Europe, the carbon price embedded in electricity markets is becoming an increasingly important planning variable for developers, utilities, and investors. While cross-border mechanisms such as CBAM have gained attention, the structural reference point for power price formation remains the EU Emissions Trading System. In practice, ETS-linked CO2 costs set the baseline for how thermal generation competes, how forward curves are priced, and how export economics evolve for non-EU systems.
Carbon costs as the baseline for dispatch and wholesale pricing
The EU ETS places a direct price on emissions, requiring generators to internalize CO2 costs in their operating decisions. For coal and gas plants, that translates into higher marginal production costs, which then feed into wholesale electricity prices. Even when wind and solar output is strong, tight-hour conditions often rely on gas or coal as the marginal unit, keeping CO2 cost embedded in both spot outcomes and forward expectations.
For EU-connected markets where fossil generation still provides balancing capacity, ETS functions as a pricing floor. This matters for project planning because it influences long-run revenue assumptions for flexible assets, including storage and firming resources that depend on scarcity pricing. It also affects how engineering studies translate fuel assumptions into dispatch models used for grid connection assessments and bankability reviews.
A split region: ETS exposure in EU systems versus non-EU pricing outside the scheme
The SEE power landscape is structurally divided between EU member states and non-EU markets. Hungary, Romania, Bulgaria, and Croatia are fully exposed to ETS pricing, while Serbia, Bosnia and Herzegovina, and Montenegro operate outside the ETS framework. That creates a divergence in how carbon costs enter generation economics across neighboring systems.
In non-EU markets without direct CO2 pricing, lignite can remain viable because it avoids ETS-related cost pressure that would otherwise penalize high-emitting generation. As a result, these systems can appear structurally cheaper when viewed purely through domestic dispatch economics. However, that apparent advantage becomes harder to sustain once cross-border trading routes start to matter more for utility strategies.
CBAM and market coupling transmit ETS logic during export periods
Cross-border dynamics increasingly determine whether non-EU generators can realize their domestic cost advantage when electricity is exported. CBAM is designed to mirror ETS costs at the border by translating carbon exposure into a trade adjustment. Unlike ETS’s continuous operation inside EU markets, CBAM behaves as a conditional overlay that activates when exports occur.
This produces layered price formation: ETS governs internal EU market economics while CBAM selectively transfers carbon costs to non-EU exporters during export scenarios. The consequence is an indirect “pull” toward ETS pricing levels for non-EU SEE markets whenever trade flows connect them to EU demand. For utilities planning generation portfolios—such as EPS or Elektroprivreda BiH—this means export competitiveness can diverge from domestic dispatch outcomes.
Early 2026 showed how hydrology and incomplete CBAM implementation can distort spreads
In early 2026, the interaction between regional hydrology and CBAM implementation created a temporary disconnect between non-EU prices and EU levels. During Q1, high hydrology in SEE coincided with incomplete CBAM implementation, allowing non-EU prices to fall well below EU benchmarks despite ETS-driven cost bases in adjacent systems. For market participants, such episodes highlight how operational conditions can temporarily override structural cost linkages.
As mechanisms normalized later in the period, the gravitational effect of ETS pricing reasserted itself. Even when SEE electricity was discounted domestically, exported volumes had to compete with EU power priced on CO2-inclusive marginal cost terms. That narrowing of arbitrage opportunities is relevant for investment planning because it affects expected utilization rates of dispatchable assets under different weather regimes.
Fuel hierarchy shifts under ETS: lignite’s domestic advantage versus cross-border constraints
ETS pricing influences fuel hierarchy by penalizing lignite heavily in EU markets when CO2 prices are high. That pushes competition toward gas or renewables depending on relative marginal costs during scarcity hours. In non-EU SEE systems without direct CO2 charges, lignite remains viable specifically because it avoids those emissions-cost adders.
The advantage becomes fragile when electricity flows toward the EU because ETS-linked pricing becomes unavoidable through either market coupling or CBAM adjustments. This creates a paradox where lignite can be cheap domestically but loses competitiveness in cross-border trade. For developers evaluating new generation or retrofits—and for operators optimizing dispatch schedules—the key challenge becomes managing portfolio performance across both domestic and export-driven revenue streams.
Forward markets in Hungary (HUPX) anchor power futures to CO2 expectations
Beyond spot trading, ETS also shapes forward market valuation in Central Europe. Power futures in Hungary (HUPX) are anchored not only to fuel prices but also to CO2 expectations that reflect anticipated EUA (emissions allowance) prices. Traders incorporate gas and coal spreads alongside regulatory tightening assumptions when pricing forward electricity contracts.
This means that even if short-term spot prices are driven by grid constraints or hydrology-driven supply shifts, the forward curve continues to reflect carbon pricing fundamentals. For procurement frameworks—whether utilities are preparing hedging strategies or industrial off-takers are negotiating supply terms—carbon-linked expectations influence contract structures even when near-term physical conditions look disconnected from emissions costs.
ETS behaves like a price multiplier when gas prices rise
The interaction between ETS and gas prices further reinforces its role in shaping overall market levels. When gas prices rise, marginal generation costs increase because gas-fired plants become more expensive to run; at the same time, those plants still emit CO2 under the trading system. The dual cost structure strengthens ETS’s effect as a price multiplier rather than a standalone component.
In 2026, rising gas prices helped offset some CBAM-induced distortions by lifting overall market prices enough to keep even discounted SEE generation economically viable during certain periods. However, the underlying driver remained ETS-linked cost structures operating through EU market formation channels rather than through any sustained change in carbon-cost fundamentals.
Implications for renewable integration, BESS planning, transmission readiness
As renewable energy and battery storage expand across the region, ETS influence does not disappear—it changes shape as solar and wind dominate daytime output. With fewer hours setting marginal prices during scarcity conditions, the CO2 signal becomes concentrated into more volatile periods such as evening peaks. That increases the importance of accurately modeling carbon-linked scarcity dynamics in technical studies used for grid connection applications and operational design of balancing resources.
Deeper integration with European electricity markets will likely increase indirect exposure to CO2 pricing for non-EU countries through accession pathways or market coupling arrangements. Over time, full operationalization of CBAM narrows distinctions between ETS-connected and non-ETS markets by extending carbon-adjusted logic beyond EU borders across export scenarios. For investors assessing CAPEX planning for transmission infrastructure upgrades or BESS execution readiness, these developments increase the need to align engineering assumptions with carbon-linked forward expectations rather than relying solely on short-term weather or grid constraints.
Broader industry takeaway
The core message for project developers and grid stakeholders is that ETS remains the central economic anchor of European power pricing: it determines marginal generation costs inside the EU system continuously and increasingly influences cross-border trade outcomes from SEE toward EU demand. As renewables reshape dispatch patterns and storage becomes more central to balancing strategies, technical studies must treat CO2-linked scarcity behavior as a key driver of revenue timing and operational value. For procurement teams preparing EPC scopes and contracting strategies—and for operators planning dispatch optimization—carbon fundamentals should be treated as an input that propagates through both spot outcomes and forward curves across interconnected markets.