​Iranian drone strikes on Qatar's Ras Laffan complex on 2 March forced QatarEnergy to halt output at the world's largest LNG export facility. Combined with Iran's closure of the Strait of Hormuz - through which 20% of global LNG flows - Dutch TTF gas prices surged 50% in two trading sessions, briefly trading above €60/MWh on 3 March for the first time since February 2025.

The immediate price shock is clear; what matters now is duration. Europe enters this disruption with storage below 30% (its lowest seasonal level in years) and a legal obligation to reach 90% full by October. A prolonged Qatari outage tightens an already difficult refilling task, lifts peak power prices across the continent, and risks reigniting the inflation that central banks have spent three years trying to bring under control.

In this piece, we look at:

• Why Asian demand is driving European gas prices higher
• How long the disruption needs to last before storage becomes a serious problem
• The impact on power prices, battery revenues, and solar assets
• What a sustained gas shock means for interest rates and new BESS investment decisions

European gas prices hit a 13-month high as Qatar halts LNG production

The Iran war has direct impacts on European energy prices: Dutch TTF gas prices (the European benchmark) surged 50% in only two days this week. The April 2026 contract traded above €60/MWh for short periods, reaching the highest gas price level since February 2025.

The direct trigger is the strait of Hormuz, which Iran has now closed and through which 20 % of global LNG flows. And fighting in the region is further impacting Qatari LNG production: Iranian drone strikes on Qatar's Ras Laffan industrial complex on 2 March forced QatarEnergy to halt production at the world's largest LNG export facility.

While over 80% of Qatari LNG volumes flow to Asia, the impact on European gas prices is no less direct. When Asian buyers lose their Qatari cargoes, they turn to the spot market, competing directly with European buyers for available US-origin cargoes. And as LNG is Europe's marginal supply source, prices have to rise high enough to win that competition.

That is what happened this week: TTF and the Asian JKM benchmark rose in lockstep. US Henry Hub prices barely moved as the US domestic gas market is already hitting its LNG export capacity and hence insulated from global price rises.

Longer-term impacts will depend on how long the disruptions to Qatari LNG last

Prices moved sharply in both directions this week as expectations about the conflict's duration shifted. That volatility reflects the market pricing uncertainty. The market may handle a one-week closure of the strait and Ras Laffan more easily, but if the war continues for longer, the missing volume may feed through to contracts further along the line.

Force majeure has been declared on some Qatari export contracts with near-term delivery, but not on those with delivery further out. A Goldman Sachs note from this week estimates that TTF could reach €74/MWh if the Strait of Hormuz remains closed for a month.

And work has been halted on the Qatari North Field East expansion, which was slated to add an additional 33 mt/yr of LNG to the market later in 2026 (about half of German annual gas demand). If works are halted for much longer, the summer heat could push commissioning back to late 2026 or early 2027.

The longer the outage runs, the more it compounds. Gas is a storable commodity. Europe needs to rebuild storage over spring and summer to be ready for next winter, and even a short-term disruption can impact storage levels further down the line.

Summer forward prices are rising strongly as Europe needs to refill its underground storage

If Qatari cargoes remain off the market during the injection season, the summer refilling task will be more difficult. Europe’s gas storage facilities are at their lowest seasonal level in years, currently less than 30% full.

But the EU mandates that storage will have to be 90% full by the end of the summer, which can be reduced to 80% in the case of “difficult market conditions”. Traders are factoring in full storage in their calculation of winter prices, keeping them comparatively low.

But that means Europe has to inject at least 575 TWh of gas this summer, the largest restocking effort in recent years. This has flipped the summer to a premium over the winter price as traders expect a tight market in the summer.

The inverted summer-winter spread has removed any incentive for commercial storage injections, which may mean that states have to step in, as they did in 2022. But summer-winter-spreads were inverted for a longer period early last year, too, and flipped back as the filling season started in April.

In the UK, this filling requirement does not apply, but because the country has barely any storage relative to demand, it often exports to European storage sites in summer and imports from Europe in winter. Summer prices have risen almost in lockstep with the EU, but kept a discount to encourage further exports to Europe.

The UK also receives more Qatari LNG than many other countries in Europe, so prices rise to replace the lost Qatari cargoes. QatarEnergy would have delivered to the Isle of Grain (a UK import terminal) under a long-term contract, but on a short-term basis, the UK’s terminals are among the most expensive in Europe.

Higher gas prices lift peak power prices, and battery revenues with them

Gas sets the wholesale power price in the majority of peak and shoulder hours across most of Europe. Whenever wind and solar output isn't sufficient to meet demand, gas plants are typically the last unit dispatched and therefore the marginal price setter. When gas prices are high, peak power prices rise in proportion.

Coal can soften the impact in markets with remaining thermal capacity, like Germany. When gas becomes uneconomic relative to coal, generators switch fuels, capping the marginal price. But since this increases demand for coal, coal prices have also risen this week.

Carbon prices act in the opposite direction: coal is more carbon-intensive than gas, so higher Emissions Trading Scheme (ETS) prices narrow the fuel-switching window. EU ETS allowances typically rise when gas prices rise, as utilities buy carbon to cover rising coal burn. But this week, EU ETS prices have remained modest, perhaps reflecting expectations of weaker industrial activity amid a renewed energy price shock.

For batteries, higher gas prices directly increase revenues. Batteries arbitrage the spread between the midday prices set by renewables and expensive peak prices. A wider spread means more revenue per cycle. In Modo Energy's sensitivity analysis, a 50% rise in gas prices combined with a 40% increase in carbon prices lifts battery revenues by 28%.

Solar capture prices also improve. Higher gas prices push up prices in the shoulder hours around the solar generation window, lifting the absolute value of solar output. Solar capture rates (the ratio of solar capture price to the baseload price) are unaffected, as they measure relative performance. But in absolute terms, solar assets earn more per MW when gas prices are high.

A sustained gas shock could delay rate cuts or push rates back above 4%

The same gas shock that lifts revenues for operating assets creates a second-order problem for new ones, via its impact on interest rates. Higher wholesale energy prices feed through to consumer inflation, complicating the path for interest rates.

The National Institute of Economic and Social Research (NIESR) estimates that if energy prices remain elevated for a year, UK CPI inflation could rise by 0.7 percentage points, with the Bank of England base rate up to 0.8 percentage points higher than previously forecast - taking it back above 4%.

BESS projects are capital-intensive and highly sensitive to discount rates. Most European projects are underwritten at a cost of capital of 5-7%, with lenders typically requiring that projected revenues cover debt repayments by at least 1.2-1.4 times. A 1 percentage point rise in the cost of capital can meaningfully compress project IRRs - potentially pushing developments that were marginal at current rates below the threshold needed to reach final investment decision (FID).

That creates a direct tension: the same shock that improves the revenue case for operating assets raises the hurdle rate for new ones, and could delay final investment decisions on projects currently in late-stage development.