INTERVIEW: UK gas grid blending would derisk hydrogen projects: Statera

Statera Energy is awaiting a UK government decision on hydrogen blending into the natural gas grid that could unlock its 3-GW Kintore electrolysis project in Scotland, as the developer seeks to capitalize on power grid constraints and existing gas infrastructure to bring early hydrogen volumes to market.

The company, which is focused on flexible energy generation and storage, views hydrogen blending as critical for de-risking large-scale projects, providing ready offtake for the variable output from renewables-powered electrolyzers, CEO Tom Vernon told Platts in an interview in late August.

Such an approach could provide a more economical solution to building additional power grid capacity, Vernon said.

"You're installing electrolyzers and using existing gas network infrastructure to essentially bypass the grid," Vernon said. "On the margin, it could be more competitive than an incremental interconnector between Scotland and England."

The plant would be connected to the power grid, close to wind farms, and Statera is planning to procure electricity on the wholesale market.

The government has opened a consultation on hydrogen blending in the gas network, which closes on Sept. 16. One option is a proposal to blend up to 20% hydrogen.

Statera's Kintore project has received planning permission and completed front-end engineering design work, with a first 500-MW phase planned for delivery by 2029, when renewable curtailment could become acute in Scotland given limited interconnector capacity.

Statera is preparing to bid in the government's third electrolytic hydrogen allocation round, HAR3, which is due to open in 2026.

Vernon said the project's costs were "much lower" than where HAR1 cleared, with the grid-connected project able to tap low-cost, surplus wind generation.

"Hydrogen makes sense when we need to start balancing high renewable power systems that have significant excess wind," Vernon said. "That's when you get the levelized cost of hydrogen down to a level that becomes economical."

The government supported a total of 125 MW of electrolysis across 11 HAR1 projects at an average strike price of GBP241/MWh (GBP9.50/kg, $12.50/kg), allocating funding in December 2024.

The Department for Energy Security and Net Zero shortlisted 27 HAR2 projects totaling around 765 MW, with a funding award expected in early 2026. A government consultation on HAR3 is expected later in 2025.

Platts, part of S&P Global Commodity Insights, assessed the cost of producing hydrogen via alkaline electrolysis in the UK (including capex) at GBP5.46kg ($7.31/kg) on Sept. 1, based on month-ahead grid power prices, while blue hydrogen production by autothermal reforming was GBP2.11/kg (including capex, CCS and carbon).

Power balancing costs

The cost of balancing supply and demand in the UK electricity system rose 10% last year to GBP2.7 billion ($3.7 billion) and is projected to more than triple by 2030 as significant amounts of new generation come online, the publicly owned National Energy System Operator said June 12.

NESO warned in its 2024/2025 report on balancing costs that UK balancing costs could reach a peak of about GBP8 billion in 2030. However, that figure could be halved if critical upgrades to Britain's grid network are brought forward and delays for wider expansion are avoided.

S&P Global Commodity Insights European electricity analyst Calum Andrews said the growth of renewables capacity will continue to outstrip the build-out of new transmission infrastructure, making any material short-term downside to balancing costs unlikely.

"With major north-south [transmission] projects -- such as the 2-GW Eastern Green Link 1 and 2 cables -- not expected to enter operation until 2029/30, curtailments for locational balancing purposes are only likely to increase over the coming years," Andrews said.

Holistic approach

Vernon said hydrogen should be viewed as part of a holistic energy system, integrating renewables and gases, particularly in areas with grid constraints where existing gas infrastructure can be utilized for low-cost, grid-connected electrolysis.

Aside from hydrogen, Statera has several battery storage projects, alongside thermal generation and hydroelectric assets.

The company powered up the UK's largest battery energy storage system in August, delivering electricity from its 300-MW Thurrock project to the grid.

It has a further 1.5 GW of storage consented across three projects, with others in planning.

Vernon said the economics for battery storage were good and getting stronger, with falling costs of battery cells and an increasing dependency on renewable power generation lifting power storage demand.

Platts assessed spreads for four-hour batteries in Great Britain at GBP89.05/MWh on Sept. 1.

The CEO said further transparency from NESO on how it prioritizes calls on dispatchable power to balance the grid would help the market.

"Everything from 1.5 hours out from delivery is really controlled by National Grid," he said. "And increasingly, that is really the most important time with the variability of renewables, a lot of supply and demand imbalances occur through that period."

"Therefore, what's very important is that we have absolute transparency in that market mechanism and how the decisions are made so that it can be accounted for and predicted," he said.

Statera also signed a memorandum of understanding in 2023 to procure low-carbon hydrogen from Kellas Midstream's proposed H2NorthEast project in Teesside, to power its nearby Saltholme thermal power stations.

Vernon said the case for green hydrogen becomes stronger the more the energy system is electrified, with the potential for large volumes of surplus generation.

The shift to a renewables-heavy power system means investments are moving away from high-capex, high-efficiency to lower capex, lower efficiency, where thermal generation plays more of a backup role.

"That does lend itself better to hydrogen-fired generation rather than [carbon capture-enabled gas-fired power]," Vernon said. "CCUS is probably more economic in a baseload application for combined cycle gas turbines, whereas hydrogen to power may be better in open cycle gas turbines or gas engines."

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Source: Statera Energy, S&P Global Commodity Insights