The gas price rose almost 40 percent in July and the power price moved with it. European gas storage is at its lowest level ever for this time of year, while the market swings back and forth between fear of escalation and hope of a deal around the Strait of Hormuz. This is what happened, and what it means for your procurement.
July began deceptively quietly. The TTF month contract, the price for delivery in the coming month, opened on 1 July at € 42.78 per MWh, immediately the low point of the month. Three weeks later the board read € 63.58, and the month closed at € 59.07. Anyone looking only at the calendar saw a summer month. Anyone looking at the market saw a price rise of almost 40 percent.
In early August part of that has run off again: the month contract is quoted at around € 53 to 55, after a peak of € 64.35 last week. The reason for that fall is hope, not fact: reports of a possible deal between Iran and Oman over the Strait of Hormuz. As long as that deal is not there, every headline will keep moving the price. Below we set out what happened in the market and which choices that calls for in your procurement.
Notably, the late July peak was higher than the peak when the conflict broke out in March. That is not panic, that is arithmetic. For every month that LNG exports through the Strait of Hormuz are halted, some 10 billion cubic metres disappear from the world market, and Qatar accounted for about a fifth of all LNG worldwide. Apart from a few short breathing spaces, those exports have now been halted for more than five months.
At the same time the buffers are thin. European gas storage stood at 56.6 percent at the end of July, the lowest level for this time of year since records began, and twelve percentage points below last year. Dutch storage is leaner still at 36.6 percent. And because gas for immediate delivery is currently more expensive than gas for the winter, there is hardly any financial incentive to fill those stores. Analysts expect a fill level of 67 to 76 percent at the start of winter, where 80 percent is the target.
Day-ahead prices per trading day. The monthly average for July came out at € 53.74 per MWh.
In the first week of August the gas price fell further. Over week 31 the month contract averaged € 59.5 per MWh, against € 60.8 a week earlier, with a peak of € 63.0 on Monday and a close of around € 59.4. In early August that came down further to roughly € 55, after the attacks were called off. The Aug-26 contract lost € 4.6 to € 59.0 and delivery year 2027 lost € 3.6 to € 41.9.
Do note what the market is actually saying there. Many traders now assume a long lasting disruption: LNG shipments through the Strait of Hormuz are expected to stay limited until the end of 2026 and to recover only in the first quarter of 2027. So the risk premium has not disappeared, it has merely flattened a little.
This week the Reuters news agency set out analysts' winter scenarios. If traffic through Hormuz normalises, gas will probably move between € 60 and € 80 per MWh this winter. If Qatar stays off the market and the winter turns cold, the average daily price between November and March could head towards € 110, with storage at 10 percent by the end of March. Anyone wanting to hold a larger buffer at that point pushes the price up further. These are scenarios and not forecasts, but they show how narrow the margin has become.
The most interesting signal is not in the price itself, but in the gap between the month contract and the year contract. Throughout 2025 that gap hovered around zero. Since the conflict it has swung between 5 and 15 euros, and since the end of June it has widened structurally, towards 20 euros per MWh.
What the market is saying is that the greatest tightness lies in the coming months, not in 2027. The price for delivery year 2027 rose as well, but far less steeply. There is simply more time to resolve the tightness: new LNG projects come online, and in December the active year contract rolls forward to 2028.
| Market | 1 July | 31 July | Change |
|---|---|---|---|
| TTF gas, coming month | € 42.78 | € 59.07 | +38% |
| TTF gas, delivery year 2027 | € 34.58 | € 41.91 | +21,2% |
| Dutch power, coming month | € 99.85 | € 123.64 | +23,8% |
| Dutch power, delivery year 2027 | € 88.30 | € 100.98 | +14,4% |
| Rotterdam coal (API2), coming month | $ 115.50 | $ 122.00 | +5,6% |
| CO₂ allowances, December 2026 | € 79.54 | € 81.26 | +2,2% |
Closing prices per market. Gas and power in euros per MWh, coal in dollars per tonne, CO₂ allowances in euros per tonne.
| Delivery year | Power base | Week | Power peak | Week | Gas | Week |
|---|---|---|---|---|---|---|
| 2027 | 101,04 | -7,21 | 107,52 | -8,05 | 41,96 | -3,67 |
| 2028 | 82,42 | -5,71 | 91,05 | -3,09 | 29,74 | -1,35 |
| 2029 | 77,04 | -1,76 | 85,26 | -1,57 | 25,53 | -0,43 |
Forward prices in euros per MWh, with the change over the week. The further out in time, the smaller the movement: 2029 came out just € 0.43 lower.
That is the risk premium peeling away in front of you. In delivery year 2027, € 7.21 came off the power price in a single week and € 3.67 off gas; in 2029 it was only a few cents. Anyone buying far ahead is buying a market that carries far less of this crisis in its price.
Two things stand out in that table. First, that the month contract rose harder everywhere than delivery year 2027: the risk premium sits mainly at the short end. Second, that CO₂ barely moved with it. At this price ratio between gas and coal, the dispatch of power stations does not shift enough for demand for emission allowances to move as well. For buyers that means the CO₂ component contributed almost nothing to the cost increase in July.
Prices are an opinion, ships that have arrived are a fact. And those ships are visibly becoming fewer. In July twelve LNG tankers berthed in the Netherlands, against twenty one in June and twenty one in May. At Dunkirk and Montoir together eight arrived, after ten in June and twelve in May. At Zeebrugge there were five tankers, after nine and twelve.
Taken together, arrivals across these three regions fell from forty five in May to twenty five in July: almost half as many cargoes in two months. That is the physical side of the same story the curve is telling.
France is Dunkirk and Montoir combined. The Netherlands is mainly Rotterdam, with a few arrivals at Eemshaven.
More interesting still is where that gas came from. Of the twelve Dutch cargoes in July, seven came from the United States. The rest came from Russia (two), Norway, Peru and Trinidad and Tobago. So America supplies almost six in every ten cargoes arriving here.
| Origin | Cargoes in July | Share |
|---|---|---|
| United States | 7 | 58% |
| Russia | 2 | 17% |
| Norway | 1 | 8% |
| Peru | 1 | 8% |
| Trinidad and Tobago | 1 | 8% |
Arrivals in the Netherlands in July 2026, by country of origin of the gas. Three tankers carrying Russian condensate also arrived.
That makes two things concrete. First, how dependent north west Europe has become on one supplier on the other side of the ocean: the Russian share of the European gas market fell from around 55 to 14 percent, while the American share climbed from virtually nothing to some 30 percent. Second, that Russian gas is still arriving, while the European ban on Russian LNG takes full effect from the end of this year. So those two cargoes a month have to be replaced as well.
One reason the power price did not rise even harder alongside gas lies in the fuel choice of the power stations. Coal became only 5.6 percent more expensive in July and emission allowances only 2.2 percent, against almost 40 percent for gas. At that price ratio, power from coal stays competitive with gas fired output, and that dampens demand for gas for power generation.
That same mechanism explains why CO₂ barely moved: if dispatch does not shift from coal to gas or the other way round, demand for emission allowances does not change either. For your cost price that means the CO₂ component contributed almost nothing to last month's increase.
The margin of gas fired plants did come under pressure. The Dutch August contract fell by roughly € 14 per MWh while gas fell much less, which narrowed the clean spark spread for August by € 4.4 per MWh. Further out along the curve those margins stayed stable or improved slightly. Where coal stays cheap and the spread stays narrow, coal plants therefore keep running for longer than the energy transition would suggest.
The power market rode along with gas. The Dutch month contract for baseload rose 23.8 percent and peaked on the same day as the gas price. So far, so predictable.
But in early August gas and power actually diverged. While gas fell slightly, the Dutch day-ahead baseload in week 31 rose to an average of € 116.0 per MWh, € 8.0 more than the week before, and the average peak price rose to € 75.2, a jump of € 13.6. That had nothing to do with fuel and everything to do with tightness on the supply side:
For anyone buying on the spot market that is the signal of the month: your bill depends not only on the gas price, but also on what is available in the Netherlands and around us.
Day-ahead prices per trading day. The peak of € 150.85 fell on 16 July, the trough of € 69.64 on Sunday 19 July.
The real story was in the spot market. The monthly average of € 105.86 concealed an enormous spread: daily averages from € 62 to € 151, 410 quarter hours with negative prices, a low of minus € 25.10 in the middle of the solar peak on 12 July and a high of € 339.01 on the evening of 29 July, when the sun dropped away while demand was still high.
Both extremes in the same month: that is the heart of it. Increasingly it is not the price level but the consumption profile that decides what you pay. Anyone who can shift consumption into the solar peak or avoid the evening peak sees it straight away on the invoice. The imbalance market was calmer in July than in June, incidentally, but stayed erratic: the most expensive quarter hour was quoted at almost € 4,000 per MWh.
Since the conflict broke out Brent has gone from around $ 70 to above $ 100, and in recent days has slipped back to roughly $ 79 to 80. Here too the trigger is hope: according to Reuters a draft agreement is on the table under which Iran would gain control over inbound traffic through the Strait of Hormuz. The discussion there turns mainly on the transit fee (Iran wants 5 to 7 percent of the cargo value, Oman around 3 percent, the United States nothing). Regional sources warn at the same time that a deal is not imminent, and nothing has been decided about outbound traffic.
There are two reasons the oil price rose less sharply than you would expect in a crisis like this. Pipelines through Saudi Arabia and the United Arab Emirates bring oil to sea outside Hormuz, and China cut its imports sharply by drawing on strategic reserves. But that overland detour has a price. Large tankers can only pass through the Suez Canal half laden, cargoes are resold several times en route and ships therefore spend longer at sea. Moving a barrel of oil from the Middle East to Asia now costs more than $ 12 in freight.
Saudi Aramco meanwhile cut its official September selling prices towards north west Europe by $ 3 a barrel across the board, while heavy crude towards Asia became $ 1.25 more expensive. That tells a story too: Europe has to be tempted into the long detour with a discount, while Asia is fighting over heavy crude. Russia now sends its oil across the Arctic Ocean to China, which pushes India towards other suppliers and has it buying Venezuelan oil in volume for the first time since 2019.
There is one side of this story that gets buried in the headlines: the insurers. Energy economist Anas Alhajji pointed out that Lloyd's of London has told shipowners their cover lapses if they pay Iran for transit. That turns the whole fee discussion on its head. An owner who pays is neither insured nor safe, and an owner who does not pay cannot get through. Until that is resolved, an agreement on paper still does not mean ships at sea.
There is also a good chance you are looking at the wrong thermometer. Everyone quotes Brent or WTI, but those are the markers for the North Sea and North America. Asia works with Dubai and Oman, and there medium sour crude climbed above $ 170 a barrel in March, then settled at around $ 155. At exactly those prices China stopped importing some 6 million barrels a day: demand destruction, not a voluntary saving. Anyone judging the crisis by a Brent price of $ 80 underestimates what is happening in Asia, and Asia is the market Europe competes with.
The alternatives have a ceiling too. Kazakhstan dropped out with 1.4 million barrels a day, and on most estimates Venezuela can raise its exports to around 1.1 to 1.2 million barrels a day before it stalls, because more would take years of investment. So India's record imports from Venezuela do not fill the gap, they move it.
In the gas market the shift is sharper still. The Russian share of the European gas market fell from around 55 to 14 percent, while the American share climbed from virtually nothing to some 30 percent. Europe has thereby moved from pipelines with fixed prices to individual ship cargoes. And on the world market the highest bidder wins.
The real physical tightness is in the products: diesel, kerosene and fuel oil. Ukrainian attacks shut down Russian refineries, which even turned Russia into a net importer of fuels, and China is limiting its product exports. That explains why oil products rose harder in percentage terms than crude. Do you run a diesel fleet, machinery or standby generators on gas oil, or move a lot of freight by road? Then you feel that tightness sooner than the Brent price suggests.
At Kaub, the best known bottleneck on the Rhine, there was 25 centimetres of water at the end of July where 300 to 400 centimetres is normal. Traded coal volume fell by three quarters and the low water surcharge rose to € 100 per tonne, against € 3 to 18 normally. Coal traders are postponing their purchasing until September. That hits the power market indirectly, because it is precisely in tight months that coal plants have to step in.
A market update is not advice for your company. These are the points we are watching most closely in conversations with business owners right now.
The month contract is jumpy, delivery year 2027 far less so. Anyone clicking in volume for 2027 or 2028 now is buying the calm of the long curve instead of the tension of the short one. Spreading across several moments remains the starting point: nobody catches the bottom.
Storage is at a historic low and the winter scenarios diverge widely. Anyone who has bought no gas volume at all for the winter is running a risk that does not suit every organisation. Hedge in steps, because this week's dip can look different tomorrow.
At these price levels an error in rates, grid charges or energy tax counts for more than ever. We check invoices as standard and reclaim amounts that have been overpaid.
With 410 negative quarter hours and evening peaks above € 300, flexibility becomes worth money. Can you shift consumption into the solar peak, or time your feed-in cleverly? Then your profile earns alongside you, whatever contract type you have.
The market is pricing hope and fear at the same time: hope of a Hormuz deal in this week's oil price, fear of the winter in the gas storage figures and the curve. Both could tip over tomorrow. What stands: historically low storage, a structurally tighter LNG market for as long as Qatar is not supplying, and a power market in which your profile counts ever more heavily. For your own planning that means: work with scenarios, spread your buying moments and have your invoices checked now that every euro per MWh carries through.
We are happy to go through your energy situation with you and show you where the opportunities are. Free of charge and with no obligation.
