Ember study: data centre load shifting can cut Ireland's peak demand by only 1.5% by 2030

The numbers are small enough to be awkward for anyone selling flexibility as the answer to data centre demand. Ember puts the load-shifting gain in Ireland at roughly 100 MW by 2030, against a projected system peak of 6.5 GW. That is 1.5%. Across the other eight markets in the study, the range is 0.1% to 0.6%, pv magazine reported on 3 November.

The reason sits in what data centres actually do. Ember assumes 35% of AI training capacity can be interrupted or moved, 5% of inference, and nothing for traditional cloud and enterprise workloads. Those low-latency jobs make up most of the installed base and, by Ember's estimate, around 87% of global data centre capacity in 2030. Apply an average utilisation rate of about 48% and the share effectively available to respond to grid stress falls to roughly 3%.

Ireland is the test case

Ireland already shows what the load looks like. Data centres account for approximately 19% of peak demand, and in January 2025, when system demand peaked at 6 GW, they drew an estimated 1.1 GW. Ember projects that share rising to 24% by 2030, with data centre demand at 1.6 GW against a 6.5 GW peak.

The timing mismatch makes it worse. A large data centre needs 200 MW to 500 MW of capacity and can be built in 18 to 24 months. Conventional grid expansion takes four to 10 years. That gap is the whole argument for treating demand as something to be managed rather than simply supplied.

The study finds that behind-the-meter generation and storage could provide nearly five times more relief than load shifting, with potential reductions of up to 2.7 GW in Texas.

Ember calls the alternative bring-your-own-capacity: keep the computing running, but temporarily replace grid electricity with on-site renewables, batteries or other backup. The workload does not move, so latency does not matter. pv magazine reports the study covers nine markets across the United States, Europe and Southeast Asia, with particular relevance to Ireland, the UK and Germany.

Britain bets on copper instead

The UK is taking the supply-side route. On Sunday 1 November, the Guardian reported that National Grid had agreed to buy 29.5 hectares (73 acres) at Dorman Point on land owned by Teesworks, the local public-private partnership, for what would be Britain's biggest substation. Sky News first reported the deal. The site sits next to a planned AI data centre spanning nearly 500,000 sq metres.

Ben Houchen, mayor of the Tees Valley combined authority, told Sky News that the constraint is speed, not ambition. "Everyone who has tried to build a datacentre in this country knows the biggest problem is getting enough power to the site quickly," he said, adding that up to 3.2 GW of capacity at the site would let the region compete for projects. Matt Pearce, National Grid's head of land, said the deal "reflects the constructive work between all those involved to enable this vital infrastructure".

The government's draft national policy statement on data centres, published the previous week, describes them as "as fundamental to our economy as the railways and electricity networks on which we have long depended". Opposition is organised anyway, from Auchtertool north of Edinburgh to Brick Lane in east London. The Guardian reported in October that AI companies told ministers they had 12 months to head off public opposition.

What solar did to Spanish prices

On the continent, the grid argument is being settled with price data. Spanish PV association UNEF estimates that solar generation cut wholesale electricity costs by €17.02 billion ($19.03 billion) between January 2025 and June 2026, pv magazine reported on 3 November. Average day-ahead prices would have been 86% higher without it: €112/MWh against the recorded €60.2/MWh.

Utility-scale plants accounted for €14.23 billion of the saving and self-consumption €2.79 billion, split €10.86 billion in 2025 and €6.16 billion in the first half of 2026. UNEF also estimates every euro invested in solar returns €8 in wholesale price savings. June 2026 was the extreme month: €69.6/MWh recorded, €162.7/MWh modelled without solar.

UNEF is careful about the limits. The analysis covers the day-ahead market only, excluding technical constraints, balancing services and forward contracts, so it does not translate into equivalent bill savings. It also concedes that gas and hydro would behave differently in a market without solar. The modelling draws on data from OMIE, Red Eléctrica and UNEF.

The money is still moving

None of this has slowed the investment case. On 3 November, heise reported that Electra and Mercedes-Benz are folding the carmaker's 47 European High Power Charging hubs, 374 charge points, into Electra's network from 1 November 2026. Thirty-one of the hubs are in Germany and six in Austria, taking Electra's German network from 50 to 81 parks. Prices for Mercedes customers at Electra sites have not been published.

In the US, the federal pipeline is contracting. An NRDC analysis published by CleanTechnica on 2 November says the Bipartisan Infrastructure Law's $36.8 billion in advance appropriations expired on 30 September 2026, and that the short-term extension to 11 December does not include the guaranteed dollars. The House BUILD America 250 Act proposal released in May would cut all of it. The Senate Commerce Committee's Chopping Block update on 27 October set out state-by-state effects.

Put together, the picture is less about whether grids get built than about who pays and how fast. Ember's contribution is to put a ceiling on one much-promoted fix. Load shifting is cheap and needs no new copper, but on its own it will not absorb a 1.6 GW data centre load in a country whose peak is 6.5 GW.