Day-ahead gas cost € 83.94 per MWh on 15 September. The last time gas was this expensive was on 30 December 2022. Power averaged € 168.61 per MWh in week 37, € 45 more than the week before. In the same week the Dutch government lowered the target for gas storage and the central banks of Europe and the United States raised interest rates. Those four things are connected.
Day-ahead gas cost € 83.94 per MWh on 15 September. On 1 August it was € 58.35. In six weeks, more than € 25 was added, over forty percent. The last day gas stood above € 80 was 30 December 2022, at the tail end of the energy crisis. Power averaged € 168.61 per MWh in week 37, against € 122.96 the week before.
Two weeks ago we wrote that the market had started to see the empty gas storage as a real problem. Since then little has improved and a lot has been added. Shipments of gas from the Middle East are still largely at a standstill, the Dutch government has lowered the target for gas storage, and the central banks of Europe and the United States have raised interest rates. That last item looks like a different subject, but it is not: rates are going up because energy is expensive. In this piece we walk through those four things, and what they mean for anyone who has to buy energy in the coming months.
The gas price rose almost every day in September. On 1 September day-ahead gas cost € 66.54 per MWh, on 11 September € 82.92 and on 15 September € 83.94. Averaged over the first sixteen days of September that was € 76.01, against € 61.48 in August. Gas for delivery next month also climbed above € 80, something that had not happened since early 2023.
The day-ahead gas price, per day from 1 August to 16 September. For six weeks it went almost exclusively up.
The cause is the same as in August, only worse. A large share of the gas Europe receives by ship comes from Qatar, and every ship from Qatar has to pass through the Strait of Hormuz, the strait between Iran and Oman. It has been virtually closed since the war between the United States and Iran broke out at the end of February. On 5 and 8 September the US Navy destroyed eight Iranian oil tankers after Iran had tried to hit an American warship. Talks between the Gulf states and Iran have broken down. Iran has proposed a limited shipping zone outside the strait, but nobody is sailing there yet. Since early August exactly one LNG tanker from Qatar has come out of the strait, bound for Pakistan. Qatar's exports have therefore been virtually at a standstill for weeks, and the same goes for the United Arab Emirates. Together those two countries normally supply about a fifth of all the LNG in the world, and for that gas there is no other route.
And even if the strait reopens tomorrow, not everything comes back. Missile strikes in March damaged Ras Laffan, the largest LNG plant in the world. About 17 percent of Qatar's export capacity is idle as a result, even once ships are allowed to sail again. How pressing that is shows in a small news item from last week: Qatar itself is looking for long-term contracts for American LNG, so it can keep supplying its own customers.
Europe feels that directly. Of the gas the European Union imported in August, 68 percent came from two countries: Norway by pipeline and the United States by ship. What arrives by ship therefore comes largely from a single supplier, and those ships can just as easily sail to Asia. You can see that in the price. Normally Asia pays a few dollars more for LNG than Europe, which is why the ships go there. In September that gap shrank to less than a dollar per million Btu, the unit in which LNG is traded. In other words, Europe is paying the Asian price to get the ships here, and that price is around 25 dollars, nine times what gas costs in the United States itself. Russia sees it too: it is delivering 44 percent less gas by pipeline than last year, the lowest since the 1970s, and this week the Kremlin let it be known that the remaining pipe of Nord Stream 2 is ready.
What is changing here is not just today's price. Gas for delivery throughout 2027 stood at € 59.52 per MWh on 15 September. On 1 September it was € 52.29, and in December last year less than € 25. So the market does not assume this will be over in a few weeks.
It does not stop at gas. A barrel of Brent crude costs 105.56 dollars and briefly topped 109 on 14 September. Brent is the North Sea oil whose price serves as the benchmark in Europe; the American benchmark WTI stood at over 102 dollars that day. Nine months ago the market was still counting on 60 dollars. The cause is partly the same: little gets through the Strait of Hormuz, and the detour Saudi Arabia had devised, a pipeline straight across the country to the Red Sea, is now under fire as well. The Houthis from Yemen have shelled the pumping stations of that line and hold the southern exit of the Red Sea. Along that route Saudi Arabia was still shipping almost four million barrels a day in June, in August less than two hundred thousand. The country is now producing less oil than in any year since the Gulf War of 1990.
Asia has its own benchmark, Oman crude, and it cost 128 dollars a barrel this week. The Chinese futures price even stood at 138 dollars. The difference with Brent is in the shipping: the ships to Asia take the longest way round. At those prices buyers switch or stop: for 2026 as a whole, consumption is expected to be 2.4 million barrels a day lower than last year, and most of that decline is in Asia. A factory that switches to coal or a refinery that closes does not come back by itself when the price falls again. That is why this crisis will weigh on demand for years after it ends.
The real squeeze is not in crude oil but in diesel. Diesel is made in refineries, and it is precisely those that are failing. The refineries in the Gulf sit behind the same closed strait as the gas, so their diesel cannot leave the region. Russia has halted diesel exports until the end of October because three of its six largest refineries are shut down or running at half capacity after Ukrainian drone attacks. And Saudi Arabia exported three hundred thousand barrels of diesel a day before the crisis, last month only eighty thousand. The result shows in the margin: European diesel now costs 75 dollars a barrel more than the crude it is made from, against 21 dollars in January. In the United States diesel costs a record 6.27 dollars a gallon, against 3.69 a year ago.
At Dutch pumps the recommended price for diesel stood at € 2.777 per litre on 16 September. The record of 8 April, € 2.819, is within reach, and petrol already broke its record this week. For a company with its own trucks or vans this is the item that shows up first. But anyone who has goods delivered feels it too: carriers pass a fuel surcharge on to their customers every month, and that surcharge rises faster than the oil price, because diesel rises faster than oil.
Power averaged € 157.66 per MWh in the first sixteen days of September. In August it was € 125.41 and in July € 105.86. In 97 hours the price was above € 200; in the whole of August there were 33. The number of hours with a negative price, in which you were paid to use power, fell from 53 to 13. If this continues, September will be the most expensive month since December 2022.
The average power price per month since September last year. January, at € 108, was the most expensive month of this year so far. Halfway through, September stands at € 158.
Three things are happening at once. The days are getting shorter, so the sun delivers less and for less time. There was little wind in September. And when sun and wind drop away, the gas plants have to take over, and they are now burning gas at over € 80. A gas plant burning gas at € 80 needs about € 145 per MWh in fuel alone to make power, and CO₂ allowances at around € 85 per tonne come on top of that. As long as such a plant is the last one that has to step in, it sets the price for everyone.
The most expensive hour was 10 September at seven in the evening, at € 473.76 per MWh. Since last year the power price has been set per quarter hour, and in the most expensive quarter of that hour the price even ran up to € 605. On 14 September power averaged € 229.40 over the whole day, the most expensive day of the month.
What a megawatt hour of power cost on average, per hour of the day, September versus August. The midday dip has become half as deep and the evening peak a quarter higher.
At one in the afternoon power averaged € 67.33 per MWh in September, in August it was € 30.75. At seven in the evening € 253.03 against € 193.39. And a morning peak has appeared: at seven in the morning the price now averages above € 200. So the cheap midday window of summer is getting smaller and the expensive hours are getting more numerous. For anyone who can shift consumption the difference remains large, but the window in which to do it shrinks every week.
Prices for delivery in 2027 rose again in two weeks. Power for the whole of 2027 went from € 117.90 to € 127.32 per MWh, over eight percent. But the most striking move is in the peak hours, the hours between eight in the morning and eight in the evening on working days. Those went from € 122.12 to € 141.31, almost sixteen percent.
| Delivery year | Power | 2 weeks | Peak hours | 2 weeks | Gas | 2 weeks |
|---|---|---|---|---|---|---|
| 2027 | 127,32 | +9,42 | 141,31 | +19,19 | 59,52 | +7,23 |
| 2028 | 96,73 | +4,88 | 104,48 | +8,33 | 36,70 | +2,40 |
| 2029 | 86,45 | +3,90 | 98,94 | +8,07 | 28,80 | +1,34 |
Prices per delivery year in euros per megawatt hour on 15 September, with the change since 1 September. In two weeks, peak hours gained twice as much as the base price.
Two weeks ago the peak price for 2027 was just over € 4 above the base price. Now it is € 14. The market is saying something specific with that: the scarcity is during the day and in the evening, not at night. In winter the sun delivers little during the day, and that is exactly when businesses are running. Anyone who consumes mainly during the day, an office, a workshop, a shop, therefore sees their own purchase price rising faster than the figure in the newspaper.
Something else stands out: coal barely moved. Coal for delivery in 2027 costs € 114.90 per tonne, half a euro more than two weeks earlier. Work through the fuel and the CO₂ allowances and a coal plant now earns about € 9.50 per MWh on the 2027 price, while a gas plant loses over € 14 per MWh on that same price. In August we already saw the Dutch coal plants produce almost double last year's output. The forward market says that will stay that way next year.
On 11 September the Dutch government decided that Dutch gas storage does not need to be as full this winter. The idea behind that storage is simple: from April to 1 November we pump gas into empty gas fields at Norg, Grijpskerk and Bergermeer among others, and in winter we take it out again. The government wanted 115 TWh in there on 1 November, about 80 percent of what fits. The European minimum for the Netherlands was 74 percent. The new target is 93 TWh, about 64 percent, and the government expects to reach it between 1 October and 1 December.
How full Dutch gas storage is, this year versus last year, with the old and the new target as a line. The old target was out of reach at this pace, the new one will be reached in mid-October.
On 15 September there was 76.7 TWh in Dutch storage, 53.2 percent. On the same day last year it was 98.6 TWh, 68.4 percent. Since 1 September, 0.58 TWh has been added per day, faster than in August. If the market keeps that up, the new target will be reached around 13 October and storage will go into winter on 1 November with about 104 TWh, 72 percent. Last year that was 73 percent. For the old target 0.81 TWh would have had to be added every day, and that pace has not been reached in a single month this year.
The government had two arguments for the reduction. First: the European Commission had already asked member states in March to lower the target by ten percentage points. Filling the storage is done by traders and suppliers, not by a government. They buy gas in summer and sell it in winter, and they only do so when it pays. Right now gas for the winter is barely more expensive than gas for today, so it does not pay. With a hard filling target the state then has to step in: buy it itself through EBN, or pay traders to do it. Then gas is bought regardless of the price, and that drives up the price for everyone. In the summer of 2022 exactly that happened, with an unprecedented spike as a result, and Germany lost billions on gas it had stocked up at the peak. Second: in the past five winters we took an average of 70 TWh out of storage, and the Netherlands has used about a quarter less gas since 2022. For an average winter 93 TWh is therefore more than enough, especially since gas also comes in from domestic fields, by pipeline and by ship.
Gasunie, the company that operates the national gas grid, responded the same day. The old target of 115 TWh was based on the coldest winter of the past thirty years, so that everyone could be supplied even then. According to Gasunie a lower target does not mean there will be too little gas, but it does mean the Netherlands is less well prepared for a cold winter.
We think both are true. The government is right that a state which must have storage filled at any cost drives up the price, for you too. But a lower target changes nothing about how much gas there is. The gas that is not in the ground on 1 November still has to be bought in January, on the spot and at the price of that moment. And the Netherlands will not be the only buyer then. LNG tankers sail to whoever pays the most. Japan, Korea and China also heat with gas in winter, and if it gets cold there, they bid against Europe. In 2022 Europe won that bidding by paying any price. That is where the bill of that year came from.
That bidding against each other is already under way, just not yet with China. In the first seven months of this year Japan received half as much LNG from Qatar as last year and is making up the difference from the United States and Malaysia. India, Pakistan, Bangladesh, Thailand and Vietnam have lost their contracted deliveries from the Gulf and have spent over seven billion dollars on spot cargoes since the war began, more than double what they would have paid under their contracts. Only China is buying little: it has Russian pipeline gas, its own production and full tanks, and its economy is sluggish. That is precisely why ships are still coming to Europe. If Chinese demand picks up in winter, that competitor joins in as well.
There is one hope, and it is called El Niño. That is a warming of the ocean near the equator that moves the weather worldwide, and this year it is strong. The seasonal models point to a mild, wet winter with plenty of westerly wind for Europe, and that means less heating. But mild weather does not fill storage and does not bring LNG back. And a late cold snap in January or February remains possible even in an El Niño year. Mild weather reduces the risk, it does not remove it.
The same picture applies to European storage as a whole: 68.7 percent on 15 September, against 80.8 percent last year. Put differently: what is now in European storage covers about 113 days of current consumption, and about 92 days if all imports were to stop. Both figures are at their lowest point since 2022. If the Strait of Hormuz stays closed all winter and no LNG comes from the Middle East, market analysts expect European storage to fall to about 14 percent in April. In a normal winter with an open strait the storage is enough. In a cold winter, in which a household uses up to a third more gas than in a mild one, it gets tight. And tight means expensive.
On 10 September the European Central Bank raised interest rates by a quarter of a percent, to 2.50 percent for the money banks park with it. Six days later, on Wednesday 16 September, the American central bank did the same: the Fed raised rates to a range of 3.75 to 4 percent. It was the first American rate hike since July 2023, and the decision was unanimous, twelve votes to none. Sixteen of the eighteen policymakers expect another hike this year.
The reason is spelled out in both decisions: energy. Inflation in the eurozone stands at 3.3 percent, and energy, up 14 percent in a year, is the largest item in it. The ECB expects inflation of 3.0 percent for 2026 and 2.5 percent for 2027, both above the 2 percent target. Fed chair Warsh said inflation has been too high for too long. Nine months ago the market was still counting on three rate cuts in 2026. As long as oil stays above 100 dollars and gas above 80 euros, they are not coming.
The bond market already shows it. The yield on ten-year US government bonds stands at 5 percent, the Dutch at 3.6 percent. In Britain, where the gas price has risen 165 percent this year, the state pays 5.95 percent on thirty-year bonds, the highest since 1998.
Why is that relevant for the energy market? For three reasons. First, interest rates feed back into the energy market itself. Suppliers who lock in gas and power for you have to post money as collateral at the exchange, and that collateral grows with the price. They borrow that money, and borrowing has become more expensive. Those costs come back in the margin you pay on a fixed contract. Second, expensive money makes new supply more expensive: a wind farm, a solar park or an LNG terminal is largely built with borrowed money, and at higher rates fewer of those projects go ahead. That keeps the market tight for longer than necessary. Third, it hits your own company: a high energy price and a high interest rate weigh on the margin and on financing at the same time.
The most important thing may be the order of events. Rates are not rising because the economy is overheating, but because energy is expensive. That means a solution in the Strait of Hormuz will bring rates down faster than any rate decision. And as long as that solution is not there, the central banks' line remains: higher, and for longer.
Peak-hour power for 2027 rose € 19 in two weeks, the base price € 9. Anyone who consumes during the day pays the top end. Have your consumption profile worked out before you compare a price.
The government is planning for an average winter. That is a choice for the treasury, not for your business. If you have a contract that follows the spot price, work out what a cold January does to your costs, and whether you can carry that.
Power for 2027 costs € 127.32 per MWh, for 2029 € 86.45. So the market attributes the scarcity mainly to next year. A contract that runs longer dilutes that expensive winter with years the market itself prices a third lower. That does require that you do not need those years to stay flexible.
In a market that has risen for six weeks in a row, you will not hit the bottom. Lock in the volume you are certain to use, in steps and at several moments. For the rest you can wait until the market turns.
In mid-September gas stands above € 80 per MWh for the first time since December 2022, evening power costs more than € 250, and the government is lowering the filling target because the old one was out of reach. The central banks are raising rates because that same energy is driving inflation. All of these things have one cause: too little gas is coming in, and nobody knows when that changes. The prevailing expectation in the market is no peace and no war, with small crises in between, until at least the American elections in November. For the energy market that is the most awkward scenario: not bad enough to make the price collapse, not good enough to let it fall.
That is no reason to sign in a panic today. It is a reason to know when your current contract ends, how much of your consumption falls in the expensive hours, and what a cold January does to your bill. We work that out for you, with your own figures.
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