Centrica and HiiROC, backed by the Net Zero Technology Centre (NZTC) , executed what is being billed as a UK first: the injection of hydrogen into a gas-fired peak power plant at Centrica’s Brigg Energy Park in North Lincolnshire, supplying electricity directly to the grid.
This milestone deserves attention, not simply as a technological novelty, but as a potentially significant pivot point in how the UK treats flexible or “peaking” electricity generation and how it grapples with the economics of hydrogen in the energy system.
What happened
- HiiROC’s modular hydrogen-production system, based on Thermal Plasma Electrolysis (TPE), produced hydrogen on-site at Brigg, which was then blended with natural gas at roughly a 3 % volume ratio for a one-hour trial run.
- The trial demonstrated that an existing gas-fired “peaker” plant can operate with a hydrogen blend, meaning that existing infrastructure may be repurposed rather than retired or fully rebuilt.
- The NZTC provided grant support, helping offset risk and cost for the demonstration.
- The trial is explicitly framed by Centrica as a contribution to the UK’s Net Zero transition and in particular, the role of firm, flexible generation when renewables are unavailable.
In short, blending hydrogen into peak gas generation is no longer just theoretical in the UK context; it’s on the grid, even if only in a trial form.
Why this matters
Peak power plants occupy a critical though often overlooked role in the electricity system. They may run only sporadically (during high demand or when renewables underperform) but they must be reliably available. Decarbonising these assets is harder than simply plugging in more wind or solar. The Brigg trial offers several implications:
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Infrastructure reuse:
Rather than build entirely new hydrogen-only plants, blending hydrogen means existing gas turbine infrastructure may be extended, upgraded, or adapted, potentially reducing stranded-asset risk.
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System flexibility:
As more intermittent renewables come online (wind, solar), the grid needs dispatchable assets, the peakers. If those assets can burn hydrogen or hydrogen blends, their carbon intensity falls, and they remain relevant.
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Signalling for investment:
The demonstration helps build the case for hydrogen’s role in the power system and may unlock investment, including in hydrogen production, storage, transport, and turbine conversion/blending.
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Policy and regulatory impetus:
To scale this from a one-hour trial to meaningful contribution means policy, regulation, and market design must recognise hydrogen’s value in the system (capacity, flexibility, decarbonisation) rather than just energy‐only markets.
But what about the economics, the LCOE question?
The levelized cost of electricity (LCOE) remains the go-to metric when comparing power technologies. It is defined as the discounted lifetime cost of building + operating a generating asset, divided by its expected lifetime energy generation.
For hydrogen-blended peaker plants, the economics are more complex, and several caveats apply:
- The cost of hydrogen production (or supply) is still higher than conventional natural gas (especially without carbon capture).
- Blending at low percentages (e.g., 3 % as in Brigg) reduces carbon intensity only modestly; to get a meaningful reduction, you eventually need higher blends or full hydrogen.
- Because peakers run infrequently (low-capacity factors), much of their cost base is fixed; their LCOE tends to be higher than baseload plants. For example, one analysis finds gas-turbine peakers built in 2024 converted to hydrogen in 2035 might reach LCOE of €0.204-0.356 / kWh (≈ £0.18-£0.33/kWh) under particular assumptions.
- A U.K.-focused study suggests that hydrogen-fired power plants commissioned in 2030 running at low utilisation (10% of the year) could reach up to £47/MWh, roughly 20% below an abated gas plant at that load factor.
- A U.S. study by Lazard shows that for new-build gas peakers (non-hydrogen) LCOE ranges from about $110-228/MWh depending on assumptions.
So, what does this imply for the Brigg case and the UK?
- At current hydrogen production and blending levels, the incremental cost of hydrogen is likely still higher than “business as usual” natural gas firing.
- However, because peaker plants are relatively short-run, high-flexibility assets, their economics depend less on fuel cost per se and more on the value of flexibility, being able to fire when needed, and regulatory compensation for capacity and carbon.
- Suppose hydrogen production costs fall (as expected with scale, learning, and cheaper renewables) and carbon pricing/regulation strengthens. In that case, hydrogen-blended peakers may become competitive, especially if they avoid the cost of new build or major conversion.
- The Brigg trial matters because it shows the technical feasibility and therefore lowers risk; lower risk → lower cost of capital → better LCOE prospects.
Why this could be an “economical solution” for the U.K. National Grid
Given the above, here’s how the Brigg model could translate into an economically viable route:
- Using existing peaker assets means capital is already mostly sunk; converting or blending hydrogen rather than building new plants minimises new investment.
- Blending hydrogen lowers carbon emissions from peakers, helping meet decarbonisation obligations without completely shutting off flexible generation.
- The value of flexible, dispatchable power increases as the share of variable renewables rises. If hydrogen-blended peakers can capture premium payments for capacity/flexibility, their LCOE relative to market revenues improves.
- If hydrogen production becomes cost-competitive (via cheap renewables, favourable policy, scale) then incremental cost falls and LCOE improves further.
- From a system view, maintaining flexible capacity that is low carbon helps avoid more costly alternatives (e.g., building entirely new firm generation, or paying large premiums for storage/flexibility). In that sense, the “economical” justification is about whole-system cost rather than just fuel cost.
In this respect, the Brigg trial suggests that the UK may be able to decarbonise a segment of its generation (peak gas-fired plants) more cheaply than building hydrogen-only plants or shutting them outright, especially given the urgency of flexibility and grid security.
But caution is required
- A 3 % hydrogen blend is modest; scaling to higher percentages (say 20 %, 50 % or 100 %) will likely require more investment (turbine conversion, hydrogen supply, infrastructure). The economics may degrade if the conversion investment is large and utilisation remains low.
- The cost of hydrogen production and transport, plus necessary storage or infrastructure, remains high relative to natural gas in many cases. Until hydrogen cost falls, the economic case is marginal.
- LCOE comparisons should factor in capacity factor, fuel cost volatility (gas is volatile), carbon pricing trajectories, and value of flexibility. Many LCOE studies assume stable fuel costs, but the UK gas price is far from stable.
- The Brigg trial is of short duration; operating issues, maintenance, turbine warranties, and integration with grid services at scale need to be tested across years for full commercial viability.
- Market/regulatory frameworks must reward the value of being a flexible, low-carbon firm generation; if they don’t, then peakers face the same pressure they already do (merit-order displacement by renewables + storage).
Haush View
The Brigg Energy Park trial by Centrica and HiiROC, supported by the NZTC, is significant: it marks a tangible step from theoretical hydrogen-in-power discussions to grid-connected demonstration in the UK. If hydrogen-blending of peaker gas plants can be scaled cost-effectively, it may become a pragmatic route to decarbonising flexible generation, one that leverages existing assets, meets future flexibility needs, and aligns with net-zero goals.
From an LCOE perspective, while hydrogen-blended peakers are not yet fully “ultra-cheap”, they may become economical in the context of the UK grid if hydrogen costs fall, carbon pricing rises, and the value of flexibility is properly rewarded. In that sense, this is not about competing with the lowest cost renewables (which have very low LCOEs) but about enabling the system to integrate more renewables by decarbonising the gap-filling generation economically.
In short, hydrogen-blended peakers may not yet be mainstream, but the Brigg trial says: “Yes, this is feasible”. The next question, and challenge, is whether the economics can scale. For the UK’s National Grid, that could make all the difference between an expensive transition and a cost-effective one.
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