Market Update September 2025

Week 1

Winter Gas Risks Persist as Storage and Supply Constraints Dominate Outlook

Despite recent price stability, the European gas market remains exposed to several structural risks. TTF spot prices hovered around €32/MWh, a level seen as a consensus price by traders. Yet this equilibrium masks key underlying drivers that could disrupt the market during the upcoming winter.

Storage levels are below the recent five-year average, and Norwegian maintenance will temporarily remove up to 10% of Europe’s daily import capacity in early September.

While the market has dismissed this as noise, it could strain injection rates ahead of winter.

China-Russia LNG Trade Alters Global Dynamics

Geopolitical developments are also shifting supply expectations. China has begun accepting Russian LNG through Arctic shipping routes, circumventing Western sanctions. This is reducing Chinese demand for US LNG, potentially freeing up supply for Europe. However, these Arctic routes will close as winter sets in, and China’s future LNG strategy remains uncertain.

Geopolitical tensions are simmering. The U.S. military intervention in Venezuela, following the capture of President Maduro, has so far had minimal impact on European gas markets. Venezuela’s export capacity remains negligible. Meanwhile, OPEC+ has extended its pause on oil production increases through March 2026. Brent M+1 prices hover around $65.50/bbl (€32.85/MWh), with EUA-adjusted cost nearing €52.00/MWh. 

Carbon prices remain high, with EUA spot at €86.33/tCO₂. Auctions resume this week and could influence short-term price movements. 

‘Today’s calm reflects consensus, not certainty. The underlying risk profile for winter is building.’
Simon Van Puyvelde, Energy Coordinator

At the same time, Spanish grid operator Red Eléctrica has confirmed that renewables will continue to be curtailed structurally, with up to 26% of potential output replaced by gas generation after recent blackouts. This reinforces expectations of higher gas-to-power demand across Southern Europe this winter.

Short-Term Calm, Long-Term Risks

Oil prices remain low but are constrained by the balance between rising OPEC output and the risk of undermining US shale production. Meanwhile, the euro remains unusually strong, currently at 1.17 against the dollar. While helpful for commodity imports, this strength may be short-lived if trade disputes shift.

Gas markets are showing early signs of speculative buildup as winter approaches. Despite low volatility now, the consensus view is that risk remains skewed to the upside. Increased gas-to-power generation, subpar storage, and global LNG competition could all drive prices higher in Q4.

Clients need to understand the timing sensitivity of forward prices and what drives them.

For insights on how these market dynamics may impact your operations or contracting strategy, speak with your Energy Manager.

Week 2

Speculative EUA buying lifts winter power, while fundamentals pull lower

Energy markets are entering the winter period with prices trending higher, but the underlying drivers are far from structural. Investment funds, having failed to move gas prices through short positions, are now turning to their other favourite play: emission certificates.

Commercials, by contrast, have already secured much of their EUA volumes. If industrial demand remains soft, they may be forced to sell part of their surplus back into the market.

The immediate result is a pricing pinch for the winter. Funds are taking long positions into the price rally, and they are currently the only player group still able to buy at scale. However, this is not sustainable. These speculative positions will need to be unwound, and with demand unlikely to recover strongly, the market is expected to shift lower once winter is behind us.

Correlation data support this view. The strong gas–power connection that shaped 2022–2024 has faded. Emissions are once again moving on their own fundamentals, and power prices are responding more to scheduling and commercial risk. This signals a return to normal market functioning, and the sentiment is becoming increasingly bearish for 2026 and beyond.

‘Speculative pressure on emissions is driving winter prices, but this will have to unwind eventually.’
Simon Van Puyvelde, Energy Coordinator

For energy-intensive clients, this leads to a complex pricing landscape. Winter 2025 remains tight, but the fundamentals may not justify forward curves for later years. The market shows little sign of structural oversupply, yet offers no clear evidence of a shortfall either. What we observe is a market driven by positioning and uncertainty, not by shortages.

We help clients interpret these market signals and manage price risk accordingly, without overreacting to temporary spikes.

To discuss how these market dynamics could affect your forward exposure, speak directly with your Energy Manager.

Week 3

Storage Stalls, New Geopolitical Shifts Emerge, and Long-Term Risks Persist

Gas prices remain soft at around €32/MWh, with injection slowing as EU storage approaches capacity. Narrow summer–winter spreads, weak injection economics, and reduced speculation continue to hold back volumes. Although familiar, these dynamics still matter given Europe’s expected colder-than-average winter, especially in high gas-to-power countries like Spain and Italy.

Meanwhile, the broader energy picture is shifting. French nuclear capacity is stable for now, with 50 out of 63 GW online. But France’s government collapse and widespread union strikes on 18 September—including energy workers—put winter output at risk. The market is watching closely whether the 58 GW base case for winter holds.

More structurally, Germany is entering talks to expand gas-fired generation beyond the 10.5 GW already planned. The country faces a 22–36 GW dispatchable power gap by 2035 due to coal and nuclear phaseouts.

On the global stage, China’s Arctic-2 LNG imports from Russia bypass sanctions and shift market expectations. Drone strikes have also disabled 17% of Russia’s refining capacity since August, creating volatility in refined product markets. Both events are reminders of how fragmented and unpredictable global energy flows remain.

‘Geopolitics are shifting, and the storage picture is fragile. Clients should not assume stability just because prices are flat.’
Simon Van Puyvelde, Energy Coordinator

Despite the uncertainty, there are concrete options. For some clients, hedging gas consumption below €35/MWh may offer a way to secure cost control for winter. Longer-term, improving efficiency, demand side response (DSR), and investing in on-site generation are critical pathways away from fossil dependency.

If you’re reassessing your winter risk or long-term resilience, reach out to your Energy Manager to explore tailored solutions.

Week 4

Markets Stabilise, But Structural Risks Persist This Winter

At first glance, energy markets appear calm. TTF gas sits at €31.86/MWh, which has been around consensus prices for a few months now, and power prices remain anchored by mild forecasts, high storage levels, and low recent volatility. But beneath this surface calm lies a network of structural tensions that could reignite volatility with little warning.

Market insensitivity to headlines is a key theme. Traders have largely discounted geopolitical shocks, with speculation shifting away from gas toward EU Allowance (EUA) markets. Yet this desensitisation can be a trap: compressed volatility often precedes sharp corrections when sentiment turns.

For gas, Europe’s reliance on LNG remains a critical vulnerability. Storage is relatively high, but injection has stalled. Norwegian flows are recovering after maintenance, and Asian demand remains subdued. But a cold winter, delayed cargoes, or pipeline incidents could quickly tighten supply. Notably, the US-EU trade deal commits Europe to massive energy imports, potentially overshooting actual demand and adding to market distortions from 2026 onward.

Ukrainian drone strikes have disabled 17% of Russia’s refinery capacity since August, increasing uncertainty in refined product markets. In France, energy strikes on 18 September temporarily cut 4 GW of nuclear output. Although 50 of 63 GW is currently online, the winter base case of 58 GW could be challenged by continued unrest. Hydro output has also seen temporary disruptions.
France’s wind rollout is at a two-decade low due to local vetoes. Meanwhile, subsidy cancellations are casting doubt on future PV deployment.

Power prices are mixed but high for now, driven by CO2 costs, increased gas burn for generation, and France’s reliable nuclear fleet. However, nuclear strike risks in France, limited wind rollout, and Belgium’s future supply gap highlight ongoing fragilities. The Belgian Planbureau’s scenario analysis shows that the cost of inaction & poor planning with regards to the nuclear phaseout could lead to significant import dependence and price inflation.

‘Low volatility doesn’t mean low risk. It means risks aren’t priced in yet’
Simon Van Puyvelde, Energy Coordinator

Clients should stay in close contact with their Energy Manager to assess how storage, hedging, and supply mix decisions might be impacted by latent volatility and shifting fundamentals.