Where my hydrogen work sits

Safety and standards

I chair Energy Institute working groups on hydrogen safety. The group I chaired from 2023 authored the UK guidance on hydrogen delivery systems for refuelling motor vehicles, covering the co-location of hydrogen refuelling with conventional petrol stations. The group I have chaired since 2024 produced the first cross-industry, regulator-supported quantitative methodology for hydrogen safety distances, which improved the consistency of planning submissions and shortened regulatory review.

I sit on BSI GSE/6 Hydrogen Technologies and participate in ISO/TC 197, and I represented first Shell and then bp in those forums. I contributed to Energy Institute Blue Book work on hydrogen infrastructure guidance. Practically, this means I can tell you which standard applies, which version of it is current, and whether a regulator will accept the argument you are planning to make.

Refuelling and infrastructure deployment

At Shell I led hydrogen infrastructure work across Europe and the USA. That included negotiating partnerships with BMW, Air Liquide and Linde, convening an intercompany alliance to define an industry-standard hydrogen fuelling system, and acting as technical lead for regulatory and planning engagement on Shell's first UK grid-integrated hydrogen refuelling pilot. I built the hydrogen supply, distribution and network-phasing models that H2Mobility Germany used for national rollout planning between 2017 and 2030.

At bp I led the fuels, land, safety, site design and regulatory workstreams for a low carbon mobility hub proof of concept, resolving the interface risks between hydrogen, EV charging and liquid fuels on a single site. Separation distances and safety case logic were my direct responsibility.

Geologic and stimulated hydrogen

Serpentinisation is the reaction between water and iron-bearing ultramafic rock such as peridotite. Iron is oxidised, water is reduced, and hydrogen is released. The reaction runs continuously in the crust wherever rock, water and temperature conditions coincide, which is why free hydrogen is found in ophiolite complexes and at mid-ocean ridges.

The commercial question is whether the reaction can be stimulated at a controlled rate and the hydrogen produced through equipment the oil and gas industry already builds. If it can, the cost base resembles upstream gas: capital in the well, low marginal cost per unit produced, and no dependence on cheap firm electricity. That is a materially different economic proposition to electrolysis.

I am Managing Director Europe at GeoKiln, which is developing stimulated geological hydrogen, and CEO of Oxford Hydrogen. The field is early. A demonstration well produces a type curve, and the question that decides everything is whether that curve supports full-scale installation at the same geology. I apply the same five tests to this that I apply to anyone else's project.

Techno-economics and investment judgement

Through RHC New Energy Consulting I chaired the advisory board of the 800 MW Southern Green Hydrogen project, advising the joint venture CEOs on investment timing, technology strategy and partner alignment, and supporting the decision to defer capital expenditure by five to seven years. I advised the Petronas board on techno-economic feasibility and offtake structuring for a $1.3bn hydrogen and ammonia production and export facility, including scenario analysis on policy, offtake and stranding risk. A techno-economic assessment I delivered for a Shell waste-to-energy project identified more than $500m of net value and enabled a partner renegotiation.

I also conducted regulatory and policy evaluations for the European Commission, contributing evidence used by DG MOVE and the Clean Hydrogen Partnership on zero-emission transport frameworks.

Questions I am asked

Is hydrogen a realistic option for home heating?

In almost all cases, no. Heat pumps and district heat deliver the same warmth for a fraction of the primary energy, and the delivered cost gap is wide enough that no plausible hydrogen cost curve closes it. Where the case is still made, it usually rests on protecting the value of an existing gas network asset.

What actually kills most hydrogen projects?

Delivered cost at the customer gate, offtake too thin or too short to finance against, infrastructure dependencies the project does not control, and consent that arrives years late. Technology failure is rare by comparison.

Should hydrogen be blended into the gas network?

Blending spreads a small percentage reduction across a large volume of demand that mostly has a cheaper electric route, and it consumes molecules that would decarbonise an industrial process outright. It can be defensible as a transitional measure to build production volume. As a decarbonisation strategy in its own right it is a poor use of scarce supply.

Does hydrogen have a role in defence and energy security?

Here the metric changes. The comparison runs against fully burdened delivered fuel, which includes the cost and risk of moving fuel to a location under contested conditions. On-site production can cost more per kilogram and still be the better answer, because the variable being optimised is security of supply rather than unit cost.

Are you against hydrogen?

I have spent twenty years on it and I run two hydrogen companies. I oppose hydrogen being put to work where electricity does the job better, because every one of those projects that fails publicly makes the genuine industrial cases harder to finance.

If you have a project at a gate