At public meetings in northwest England, David Parkin, project director of one of the UK’s two giant blue hydrogen projects, HyNet NorthWest, often finds himself on the receiving end of a heated protest. The exact phrasing of the protest varies in content and intensity, but the gist is this: “You’re just a big oil company and you pollute everything.”
Parkin is actually director of Progressive Energy, a UK company entirely focused on decarbonising heavy industry. But what his detractors have locked on to is that HyNet plans to make blue hydrogen from natural gas — a fossil fuel — with carbon capture and storage (CCS).
The project aims to split methane into hydrogen and carbon via autothermal reforming (ATR), capturing 97% of the CO2 produced and transporting it to subsea caverns for permanent storage. CCS has also attracted criticism from environmental groups, which say that is it merely a fig leaf for Big Oil’s plans to continue extracting fossil fuels indefinitely — keeping their shareholders in dividends at the expense of the planet.
The blue hydrogen produced would then be used in the factories, power stations and refineries that dot the area around Liverpool, with the wider HyNet scheme also capturing carbon from energy-from-waste and cement plants. Ultimately, HyNet aims to remove ten million tonnes of carbon from the atmosphere per year.
But issues of cost — especially in light of an almost quadrupling of the wholesale price of natural gas in the UK this year — and questions around the attractiveness of blue hydrogen compared to green remain.
An opposition group has formed in northwest England — called HyNot — and protests have spread to a related hydrogen-for-heating pilot project in the village of Whitby. That scheme was originally set to use blue hydrogen from HyNet, but developer Cadent, the local gas distributor, has now said the project will use green H2.
Nevertheless, Parkin is philosophical about the antipathy he sometimes encounters, noting that HyNet has the support of both national and local government, and the project’s industrial customers — which form the backbone of the business case for HyNet’s initial phases.
“I’m not particularly combative and I don't want to go there and have a fight and bash other technology options, such as electrification or anything else,” Parkin tells Hydrogen Insight. “I just try and look at it from a numbers perspective, see the size of the task, and recognise we need multiple solutions to reach net zero. But sometimes I feel that we’re on the defensive when we perhaps don’t need to be.”
It is easy to see why HyNet’s critics are alarmed, however. The project is enormous in size and scope, with infrastructure snaking across England’s northwest, included a new 125km pipeline, storage caverns, industrial fuel switching, domestic heating projects, offshore carbon storage and carbon dioxide pipelines (see panel below for details).
And if HyNet comes to fruition, it will be relying on fossil gas for decades to come — and the dangers of doing so, both from an economic and climate perspective, are all too apparent.
A final investment decision (FID) is expected to be taken next year for both the hydrogen and CCS elements. And for that to happen, the project developers needs to win planning approvals and financial support, and ensure that regulatory frameworks are in place.
“What we need is government to put in place a business model to allow project partners such as Eni and Cadent to invest and deliver the pipeline infrastructure,” says Parkin. “They're doing the engineering, they're doing consenting, but we need the commercial framework to allow that infrastructure to be invested in.”
In fact, the pipeline could prove to be a major stumbling block for the project.
A regulatory and fiscal framework for both the CCS and hydrogen plant appears to be under way, with HyNet selected by the UK government for access to the £240m Net Zero Hydrogen Fund. But there has not yet been a decision from the government on the regulatory model for hydrogen pipelines, and the Cadent project was thrown an additional curveball in November 2022 when Warrington Council, one of the local authorities on the pipeline’s route, lodged an official planning objection saying it would disrupt a local housing development.
Higher costs
But perhaps the biggest hurdle of all to securing those all-important binding offtake agreements is the thorny issue of cost.
When it initially pitched the HyNet project to the UK’s Department of Business, Enterprise and Industrial Strategy (BEIS) back in 2021, Progressive Energy estimated that the first 350MW phase of Hynet could deliver a levelised cost of hydrogen (LCOH) of £43.46 ($51.70) per MWh — or £1.44 ($1.72) per kg — reducing to £35.62/MWh ($1.44/kg) once the project is scaled up.
This, Progressive said, compared very favourably to the price of fossil gas that their potential industrial customers were using, especially if the carbon price were to rise and add extra cost.
But around half of that LCOH figure is comprised of fossil gas costs — at 2018 prices. Since then, the price of gas in the UK has risen as much as four-fold, and even if HyNet is saving on carbon costs associated with fossil gas, the uncertainty in the market undoubtedly puts pressure on the underlying business case.
S&P estimated last year that blue hydrogen produced with an ATR in the UK would yield blue H2 at around £3.93/kg ($4.76/kg). But a recent report from Carbon Tracker warned that blue hydrogen costs had increased by 50% since Russia’s invasion of Ukraine.
“Yes, clearly the natural gas price, because it is the feedstock, which goes into the process is a pass- through onto the hydrogen price,” Parkin says, although he will not be drawn on HyNet’s estimated cost of H2 on 2022 prices.
Analysis from Hydrogen Insight suggests that if HyNet were producing blue hydrogen today, at September gas prices of £89.88/MWh, and assuming none of the other variables such as cost of capital had changed, the LCOH would sit at £111.71/MWh or £3.72/kg ($4.51/kg) — an eye-watering 157% higher than its earlier estimates.
At this LCOH, HyNet would barely be competitive with today’s green hydrogen produced in the Iberian peninsula.
If, on the other hand, European and UK gas prices settle at around €30 (£27) per MWh by 2030, as predicted by Rystad Energy, HyNet could produce blue H2 at around £48.83/MWh (£1.63/kg or $1.97/kg), around 12% higher than Progressive originally estimated but still cheaper than today’s green hydrogen.
But by that time, the first phase of the project could have been in operation for four years — during which time it would either have had to pass the cost of volatile gas prices on to its customers, or absorb the extra cost itself.
This level of unpredictability on commodity prices makes FID far more difficult, but Parkin says that hydrogen producers will benefit from the stability of the UK government’s planned Contracts for Difference (CfD) scheme, which will essentially subsidise the cost of blue hydrogen.
In fact, he believes that the market price of H2 will eventually take on a life of its own.
“Over time as the cost of carbon goes up, the cost of natural gas plus the cost of carbon will exceed the cost of hydrogen,” he tells Hydrogen Insight. “So in future, you'll end up with a price discovery process where the cost of hydrogen will be disconnected from the cost of natural gas.”
Upstream methane emissions
Nevertheless, blue hydrogen plants are likely to struggle to meet the UK government’s CfD emissions intensity threshold of 20g of CO2-equivalent per MJ of hydrogen produced — which translates to 2.4kg of CO2e per kilogram of H2, which includes upstream methane emissions. Analysts have suggested that this would mean any blue H2 plant would have to deliver a 0.1% methane emissions intensity and a 96% carbon capture rate.
HyNet plans to procure its gas from the Norwegian or UK continental shelf, which could give the project a fighting chance. Norway’s Equinor, which produces much of the country’s fossil gas, has a methane emissions intensity of 0.02%. The UK’s upstream producers, on the other hand, have an average methane emissions intensity of 0.23%.
“We haven't yet explored that as part of our potential supply groups and we’re still in the early stages of discussing supply agreements, but yes, I would expect that we would require some level of verification on upstream emissions,” says Parkin. “Whatever is set out in that standard in terms of monitoring verification, we will clearly be compliant with.”
Is carbon capture rate realistic?
The project also has a boilerplate carbon capture rate of 97%, but some remain sceptical of the cluster’s ability to reach that figure. Almost every carbon capture project in the world so far, from Quest in Canada to Gorgon LNG in Australia, has missed capture targets by a mile, but Parkin says that the UK has the support framework to ensure the HyNet and the East Coast clusters buck the trend of failure.
“A lot of the reasons why CCS has not happened at scale has slightly less to do with the technical side and more on the institutional framework,” he tells Hydrogen Insight. “The UK government is doing very well in terms of setting up the right regulatory structures, setting up the right commercial frameworks and government policy.”
The capture technology is not new. Parkin notes that the Johnson Matthey hydrogen and carbon capture technology planned for HyNet has already been in use in methanol plants the world over.
He admits that there is some long-term risk regarding the storage caverns but insists that the UK’s regulatory framework has been designed to ensure the carbon does not escape.
“These assets have been filled with high-pressure hydrocarbons for millions of years,” he says. “The fundamental integrity of that geological structure we’re very confident about. But the North Sea Transition Authority [regulator] requires us to measure for leakage both during the operational phase and post closure. The infrastructure to get from the capture plant to the offshore rig is a large-diameter, high-pressure steel pipeline, which the UK gas industry uses all over the country and doesn’t leak.”
Why not just use green hydrogen?
But why go to all this trouble trying to reduce emissions off a fossil-based project when green hydrogen is getting cheaper all the time, with all the potential to produce renewable hydrogen from offshore wind in the nearby Irish Sea?
In fact, Progressive Energy has already jumped on this train, announcing in October plans to produce green H2 for the HyNet project with partners Statkraft and Foresight.
Together, they plan to develop a 100MW “suite” of green H2 projects, starting with a 28MW scheme that will use power from the nearby 50MW Frodsham onshore wind farm.
But Parkin, who says that HyNet has been designed with both green and blue hydrogen in mind, doesn’t believe there is a one-size-fits-all approach.
“Fundamentally, the need case for CCS-enabled hydrogen is absolutely still there,” he explains. “Yes [gas] price is an interesting question in this — but the electricity price has gone up as well because it's dependent largely on the gas price.”
He adds: “Our main concern about the ability of electrolytic hydrogen to roll out at scale quickly isn't necessarily a price-point discussion. It is just as much [about] where we find the volumes of low-carbon electricity. It’s a scale issue.”
To illustrate this, he points out that 4GW of hydrogen demand — roughly the size of HyNet’s planned 2030 capacity — would require about 6GW of green electricity, which in turn would require around 12GW of offshore wind capacity, 0.7GW more than the UK has installed to date.
“I personally struggle to see a world in which the UK meets all of its demand for hydrogen from indigenously produced green hydrogen,” he says. “I'm just not sure that we've got the scale of renewables to deliver that.”
“That said, the UK does have around 4TWh of curtailed renewable energy, which could be used for green hydrogen production,” he adds. “However, that is against a forecast demand for hydrogen that many commentators have at around 300TWh a year by 2050.”
Moreover, he believes that there is a case for leaving the UK’s offshore wind sector to prioritise the decarbonisation of electricity.
“For the foreseeable future, the UK needs every electron of low-carbon electricity it can get as electricity,” he says. “There isn't that much spare to be converting into hydrogen.”
Also, if blue hydrogen can scale up more quickly over the next decade, it can develop the hydrogen infrastructure needed, such as storage and pipelines, to make domestically produced green hydrogen a reality in the long-term, Parkin adds.
But wouldn’t HyNet’s offtakers prefer a PR-friendly green hydrogen project with bona fide renewable credentials?
“We do get asked the question,” Parkin admits. “The majority of our offtakers are pretty pragmatic. Their view is they can see a route to 90% emissions reduction very quickly with the [blue] hydrogen, which we’re providing. It's far, far harder for them to get to 100% emission reduction with green hydrogen in the foreseeable future. So this is very much a case of doing what you can, when you can, and making big steps forwards, and not letting the perfect be the enemy of the good.”
And he would prefer HyNet’s critics to take a similarly pragmatic approach.
“How else are you going to take 10 million tonnes of carbon dioxide out of the northwest [of England]?” he asks. “We just don't see [any] other credible route to be taking this level of carbon dioxide emissions out of industry in the northwest. It’s very difficult to see a route through it without doing what Hynet does.”
This large, complex proposal is one of two major blue hydrogen projects under development in the UK as part of industrial clusters combining H2 and CCS — the other is BP and Equinor’s East Coast Cluster in northeast England — with the aim of helping the country reach its target of 10GW of clean hydrogen production capability by 2030.
The hydrogen element is being led by Progressive Energy in a 50:50 joint venture with Indian Oil refiner Essar Oil. The two companies, as Vertex Hydrogen, plan to build a 3.8GW hydrogen production facility at the Stanlow Manufacturing Complex in Ellesmere Port, near Liverpool, which also houses Essar’s giant Stanlow refinery.
Italian oil giant Eni, owner of depleted gas fields in the Liverpool Bay, is leading the CCS element of the project, building a CO2 pipeline and preparing two gas fields, Hamilton and Lennox, to store carbon dioxide from the HyNet hydrogen plant and other industrial emitters in the area. The company claims it can store 97% of emissions from the HyNet cluster. Operational start-up is planned for 2025.
The Stanlow hydrogen facility is slightly further down the development pipeline. Progressive and Essar envisage 350MW of hydrogen production by 2026, with 700MW coming on line in 2027. A further scale up to 3.8GW could happen in two additional phases by 2030.
The integrated plant encompasses a gas-heated reformer (GHR) and autothermal reformer (ATR) that will produce a syngas of hydrogen and carbon dioxide. The gas then passes through a carbon removal process at pressure, producing a stream of hydrogen and another of carbon dioxide that can be transported off-site via Eni’s pipeline.
According to Vertex, the ATR can produce hydrogen at 93% efficiency (as opposed to steam methane reforming efficiency of around 80%) by introducing oxygen into the reformer instead of burning methane in air.
Project partner Cadent is working on a brand new 125km hydrogen pipeline to deliver hydrogen to both long-term storage and HyNet’s customers, which in the first phase of the project would be large-scale industrial users.
In principle, the project appears to have no shortage of interested parties.
So far, Vertex Hydrogen has secured “heads of terms” — essentially, a memorandum of understanding — with Essar to supply 280MW of H2 to the Stanlow Refinery to decarbonise its existing hydrogen production and to use in its new hydrogen furnace, delivered in August, to provide heat for the refining process. This accounts for almost all the output of the first phase of the scheme.
Two big fossil-gas users in the area, Unilever and Pilkington Glass, took part in a hydrogen fuel-switching trial facilitated by Progressive Energy last year. And HyNet has also secured memoranda of understanding from 28 different industrial energy users in the area to offtake hydrogen in the future — mostly to replace fossil gas in on-site power production, or for industrial heat in glassmaking.
In total, these add up to around 4GW, Parkin tells Hydrogen Insight, all of HyNet’s capacity to 2030.
