January 2026 confirmed that oil and gas remain structurally embedded in South-East Europe’s energy and industrial cost base, even as renewables expand. While electricity markets attracted the most attention through visible price spikes, the deeper driver of January stress lay in gas-linked marginal pricing and oil-indexed cost transmission across power generation, industry and transport. The month did not represent a temporary shock; it functioned as a compressed demonstration of how fossil fuel exposure continues to shape SEE energy economics during winter.
Natural gas was the primary transmission channel. During January, regional gas prices moved firmly back into the €40–50/MWh range, with short-lived spikes above €55/MWh during colder periods and storage drawdowns. For SEE systems, where gas-fired generation often sets the electricity marginal price during winter peaks, this translated almost one-for-one into power market stress. A combined-cycle gas turbine with a heat rate of 6.5–7.0 GJ/MWh requires a gas price below €30/MWh to keep power clearing comfortably under €80/MWh. January pricing pushed implied gas-to-power break-even levels well above €100/MWh, which is precisely where electricity prices repeatedly settled.
Unlike in parts of Western Europe, SEE gas exposure is magnified by structural factors. Storage coverage remains uneven, interconnection capacity is limited, and procurement strategies are often shorter-term or indexed rather than fully hedged. January therefore punished buyers relying on spot or month-ahead gas purchases. For industrial gas consumers—fertilisers, chemicals, ceramics, food processing and district heating operators—January gas input costs exceeded base-case assumptions by 30–60 %, depending on contract structure. For a mid-sized industrial user consuming 0.8–1.2 TWh of gas annually, January alone can add €3–5 million to annual fuel costs relative to expectations formed under calmer market conditions.
Oil markets played a different but complementary role. Brent crude traded in a relatively stable $78–85/bbl corridor during January, but oil-linked gas contracts and refined product pricing transmitted winter premiums into SEE economies through transport, logistics and backup generation. Fuel oil and diesel prices used in peak power units, industrial boilers and emergency generation followed crude with a lag, keeping variable costs elevated precisely when electricity systems were under the most stress. In countries where oil-fired capacity still exists as reserve or balancing generation, January reinforced its role as a cost-of-last-resort option rather than a competitive supply source.
The interaction between gas and electricity markets was decisive. Gas did not simply rise in price; it reasserted itself as the marginal fuel. Each €10/MWh increase in gas prices added roughly €15–18/MWh to gas-fired power marginal costs once efficiency and carbon exposure are included. January gas movements therefore mechanically locked electricity prices into triple-digit territory during peak hours. This dynamic explains why renewable capacity additions alone did not suppress prices: renewables reduced average energy needs, but gas still priced scarcity.
From a trading perspective, January rewarded gas portfolio holders with optionality and punished those without it. Traders with access to storage, flexible LNG slots or cross-border arbitrage routes captured winter spreads between hubs and end markets. Conversely, utilities and industrials locked into rigid supply structures faced asymmetric exposure: upside was capped, downside was fully open. This asymmetry mirrors what electricity markets experienced, reinforcing the idea that oil and gas risk is now fundamentally a volatility management problem, not a volume problem.
For oil markets, the January lesson in SEE was less about absolute price and more about cost stacking. Oil-indexed fuels feed into transport, mining, construction and backup generation. When combined with high electricity and gas prices, oil-linked costs amplified total energy input inflation. Even with Brent relatively stable, refined product prices in the region reflected winter demand, logistics constraints and tax structures, keeping diesel prices elevated. For heavy industry and logistics-intensive sectors, January energy costs rose across all vectors simultaneously, eliminating the possibility of internal hedging between fuels.
The implications for policy and corporate strategy are direct. First, January reaffirmed that gas remains the true system risk variable in SEE. As long as gas sets the power margin in winter, electricity prices will remain hostage to gas volatility. This places a premium on reducing marginal gas exposure rather than average gas consumption. Wind generation with winter-weighted output, hydro flexibility and firmed renewables directly attack this marginal role; solar does not.
Second, January exposed the weakness of partial decoupling narratives. Even with increasing renewable penetration, oil and gas continue to determine short-run price formation during stress. Industrial strategies premised on declining fossil relevance underestimate this persistence. Gas procurement, storage access and contract shaping are now as critical to competitiveness as electricity sourcing.
Third, January strengthens the economic case for fuel-agnostic risk integration. Companies managing electricity, gas and oil procurement separately absorbed compounding risks. Those with integrated energy strategies—coordinating gas hedging, power PPAs and backup fuel procurement—were better positioned to absorb January stress. The month demonstrated that siloed energy management is no longer viable in SEE’s winter-driven system.
From an investment perspective, January also sent a signal to capital markets. Gas infrastructure with flexibility—storage, bidirectional interconnections, LNG access—retains strategic value even under decarbonisation trajectories. However, its value increasingly lies in risk mitigation rather than growth. Assets that reduce winter price spikes earn system rents; those that merely add volume do not.
January 2026 did not reverse the energy transition in South-East Europe. It clarified its constraints. Oil and gas remain decisive during winter, not because renewables have failed, but because system design still allows fossil fuels to price scarcity. Until wind, hydro, storage and firmed renewable capacity consistently displace gas at the margin in January conditions, oil and gas will continue to set the economic tone of SEE energy markets.
The lesson from January is therefore not about resisting transition, but about sequencing it correctly. In South-East Europe, the path away from fossil dominance runs through winter. Gas and oil will continue to matter until the system is built to operate without them when demand is highest. January simply made that reality impossible to ignore.
By virtu.energy
