The withdrawal of Russian ownership from oil assets across South-East Europe has triggered a deeper and more destabilising shift in the region’s natural gas markets. While oil ownership changes are visible and politically managed, gas has become the silent transmission channel through which volatility, balance-sheet stress and structural dependency now propagate. Unlike oil, gas markets in South-East Europe lack storage depth, diversified supply routes and liquid trading hubs. The exit of Russian downstream influence in oil has therefore not reduced exposure to energy risk; it has concentrated it.
For more than two decades, Russian gas functioned as the system stabiliser for the Balkans. Prices were politically mediated, volumes were predictable and contracts smoothed seasonal volatility. Ownership links between Russian producers, regional distributors and downstream energy companies created an implicit risk-sharing mechanism. That system is now gone. What has replaced it is not a competitive market in the Western European sense, but a trader-driven, short-horizon system in which price formation is increasingly detached from local fundamentals and tied instead to global LNG cycles.
The pre-crisis gas architecture
Before 2022, South-East Europe was one of the most gas-dependent regions in Europe in proportional terms. Serbia, North Macedonia and Bosnia and Herzegovina sourced between 70% and 95% of their gas from Russian supply routes. Even Romania and Bulgaria, which possessed limited domestic production, relied on Russian imports to balance seasonal peaks. Gas was not merely a heating fuel; it underpinned district heating systems, fertiliser production, petrochemicals and a growing share of flexible power generation.
Pricing was equally distinctive. Long-term contracts indexed to oil products or basket formulas delivered gas at effective prices of €15–20/MWh for much of the 2010s. Seasonal volatility existed but was muted. Storage, while limited, was sufficient under conditions of predictable flow. In Serbia, total annual gas consumption of roughly 2.5–2.8 bcm was supported by a storage system of under 0.5 bcm, a ratio that would be considered dangerously low in Western Europe but was acceptable under stable upstream supply.
The economic logic of this system rested on Russian upstream risk absorption. Price shocks were absorbed within vertically integrated structures rather than passed through to end-users. This implicit subsidy was never recorded on state balance sheets, but it was real.
Sanctions, ownership exit and the collapse of price smoothing
The exit of Russian ownership from oil assets did not directly sanction gas flows, but it removed the institutional architecture that allowed gas price smoothing. With oil assets transferred to European corporates and trading houses, the remaining gas relationship became purely transactional. Long-term contracts gave way to shorter tenors, indexation shifted toward hub-linked pricing, and counterparty risk moved from producers to traders.
The immediate effect was price volatility. Between 2022 and 2024, average import prices for gas in South-East Europe oscillated between €35 and €55/MWh, with extreme spikes well above that range during winter stress periods. Even as headline European prices softened in 2024–2025, SEE importers continued to face a structural premium of €5–10/MWh due to transport constraints, smaller contract sizes and limited bargaining power.
This repricing translated directly into macroeconomic stress. Regional gas import bills rose from approximately €1.2 billion annually before the crisis to €2.5–3.2 billion, depending on price assumptions. For Serbia alone, gas imports that once absorbed under 1% of GDP now periodically approach 2%, creating a persistent drain on the current account.
Storage: The core structural weakness
The most critical constraint in the post-Russian ownership environment is storage. South-East Europe entered the crisis with a structural deficit that is now impossible to ignore. Regional storage capacity covers barely 20–25% of annual consumption, compared with 35–45% in Central Europe. In absolute terms, the region faces a shortfall of roughly 2.5 bcm relative to minimum security benchmarks.
This deficit has direct financial consequences. Without storage, utilities are forced to buy gas closer to consumption periods, when prices are highest. Seasonal arbitrage, once an implicit feature of Russian supply contracts, must now be purchased at market rates. The result is an embedded volatility premium in utility OPEX that cascades into electricity tariffs, district heating prices and industrial costs.
Addressing this gap is capital-intensive. New underground storage facilities or major expansions would require cumulative CAPEX of €1.8–2.3 billion across the region by 2030. Individual projects typically carry price tags of €250–400 million and long lead times, making them politically difficult but economically unavoidable.
The trader-driven market model
In the absence of upstream ownership links, gas markets in South-East Europe are increasingly intermediated by international trading houses. These actors do not absorb volatility; they monetise it. Margin structures are built around short-term spreads, optionality and risk premiums rather than long-term price stability.
This model favours entities with access to LNG portfolios, shipping capacity and balance-sheet strength. For SEE buyers, however, it introduces a structural asymmetry. Small volumes, fragmented demand and limited storage mean weaker negotiating positions. Even when global LNG markets loosen, the benefits reach SEE last and incompletely.
The financial implication is a permanent increase in gas procurement OPEX. Compared with the pre-crisis baseline, utilities should assume structurally higher costs of €10–15/MWh, even in benign market conditions. For a country consuming 3 bcm annually, this translates into €300–450 million of additional annual expenditure.
Power generation and the gas paradox
Gas was expected to play a stabilising role in the energy transition, replacing coal and lignite while supporting renewable integration. In South-East Europe, this strategy now looks increasingly fragile. Gas-fired power plants face fuel cost volatility that undermines dispatch economics, while carbon pricing further compresses margins.
New combined-cycle gas turbine projects in the region face CAPEX of €700–900 per kW, with levelised costs highly sensitive to gas prices. At €20/MWh, gas-fired power is competitive; at €45–50/MWh, it is not. This creates a paradox in which gas capacity is needed for system stability but struggles to achieve bankability without state guarantees or capacity payments.
The result is growing contingent liability on public balance sheets. Capacity mechanisms, fuel price hedging and state-backed offtake agreements are increasingly necessary to make gas projects viable. These mechanisms shift volatility from utilities to governments, often without transparent accounting.
Industrial exposure and competitiveness
For industry, gas repricing is not merely an energy issue; it is a competitiveness shock. Fertiliser producers, chemicals, food processors and district heating operators face OPEX increases of 20–60% compared with pre-crisis norms. In sectors with thin margins, this erodes profitability or forces output reductions.
The cumulative effect is de-industrialisation risk at the margin. While SEE economies are not heavy gas consumers by absolute volume, they are highly sensitive due to limited ability to pass costs downstream. Over time, this favours import substitution and offshore production, widening trade deficits and reducing domestic value creation.
Medium-term outlook to 2030
Looking forward, the gas market in South-East Europe is unlikely to revert to its pre-crisis equilibrium. Even under optimistic scenarios, Russian gas will remain a supplier but no longer a stabiliser. The ownership exit in oil has symbolised a broader shift: energy inputs are now priced as commodities, not political instruments.
By 2030, the region is likely to operate in a gas price band of €30–45/MWh under normal conditions, with winter spikes remaining a persistent risk. Storage expansion will mitigate but not eliminate volatility. LNG access will improve flexibility but embed global price transmission.
Cumulative gas-related CAPEX across infrastructure, storage and power generation is expected to exceed €3–4 billion by the end of the decade. Annual gas import bills are unlikely to fall below €2 billion even in low-price environments.
Who wins, who loses
The winners in this new system are international gas traders, LNG portfolio holders and infrastructure owners able to extract scarcity rents. The losers are state utilities, industrial consumers and, ultimately, households facing higher and more volatile energy bills.
For governments, the challenge is not to recreate the old Russian-anchored model, but to design transparent mechanisms that manage volatility without disguising it. Failure to do so risks turning gas into the region’s permanent macroeconomic shock absorber.
Gas as the new stress point
The exit of Russian ownership from oil assets has not reduced South-East Europe’s energy vulnerability. It has relocated it. Gas has become the system’s most exposed node, transmitting global volatility directly into domestic economies with limited buffers.
In this sense, gas markets now define the region’s energy risk profile more than oil ever did. Until storage deficits are addressed and pricing mechanisms are stabilised, volatility will remain not a temporary disruption, but a structural feature of the South-East European energy economy.