UK production of blue hydrogen is projected to reach 0.5mn tonnes by 2030 and 2.5mn tonnes by 2050, according to DNV
Blue hydrogen must meet high carbon capture rates and utilise low emission natural gas to hit demanding low-carbon thresholds
The UK North Sea has a low emissions competitive advantage relative to LNG imports. However, more must be done to lower methane emissions and boost production if blue hydrogen in the UK is to remain low carbon
Blue hydrogen economics – relative to grey and green – is heavily dependent on the outlook for natural gas and carbon prices and the cost of electrolysers

UK low-carbon hydrogen production capacity is forecast to increase to 5 GW in 2030 according to recent analysis of the UK’s energy transition by DNV. Blue hydrogen should account for most of the capacity in 2030, followed by a small amount of green hydrogen, from electrolysers.

DNV based its blue hydrogen forecast to 2030 on the current project pipeline for Track 1 and Track 2 clusters, taking account of the likelihood of delays.

The projection indicates that the UK government will not meet its ambition – outlined in the British Energy Security Strategy (BESS) – of up to 10 GW of low-carbon hydrogen production capacity by 2030, “subject to affordability and value for money, with at least half of this electrolytic hydrogen.”

Source: DNV

Beyond 2030, DNV project the UK’s low-carbon hydrogen capacity will increase to around 16 GW in 2035. It will then reach 48 GW in 2050.

Time to split

By 2050, their analysts project total low-carbon hydrogen production in the UK will have reached almost 5 million tonnes per year. Of this, this around 50% will be blue hydrogen. The other 50% is split between dedicated renewable and grid-connected electrolysis.

According to DNV, the long-term outlook is heavily dependent on the relative cost of blue hydrogen compared with green hydrogen, and overall demand for the resource from sectors seeking to decarbonise. However, to even begin to reach its full potential, blue hydrogen producers must be able to demonstrate their capacity.

Demanding thresholds

The overall life-cycle emissions associated with producing blue hydrogen depends on two broad factors. These are the overall efficiency and capture rate of the carbon capture technology, and the upstream emissions associated with natural gas extraction, processing, and transportation.

Steam methane reformer (SMR) technology is the main producer of blue hydrogen. This process brings together natural gas and heated water in the form of steam. The output is hydrogen, with CO2 as a by-product. If the CO2 is captured and permanently stored it can be described as low-carbon hydrogen.

Autothermal reformer (ATR) technology also produces blue hydrogen and is typically more energy efficient than SMR.

According to research carried out by DNV, both SMR and ATR can reach overall carbon capture rates above 90%. For SMR, this depends on the choice of carbon capture location within the plant.

For example, carbon capture rates at SMR with syngas or tail gas are ~50-55%. This rises to 90-95% when emissions are captured via SMR with flue or combined syngas and flue, or by using ATR. In early 2023, the UK Environment Agency issued guidance saying that blue hydrogen plants must capture a minimum 95% of the emissions, unless they have a good reason not to.

Supply chain

The single most important factor determining the emissions intensity of blue hydrogen is the supply chain emissions associated with the production, processing, and transportation of natural gas.

For example, DNV’s analysis shows that blue hydrogen can meet the UK’s Low Carbon Hydrogen Standard (LCHS) of 2.4 tonnes of CO2e per tonne of hydrogen, but only by using a very low-carbon natural gas feedstock.

Emissions for blue hydrogen production technologies

Source: DNV

As I explain in Why the UK North Sea must become a low carbon leader, it’s here where the North Sea is at a competitive advantage relative to LNG imports.

The UK receives much of its gas via pipeline from Norway. The carbon intensity of these supplies is estimated to be 8 kgs CO2 per boe. UK domestic production is estimated to be more than 2.5 times higher at around 21 kgs CO2 per boe.

By contrast, LNG imports, which account for almost 30% of UK gas requirements, have a carbon intensity of 79 kg CO2 per boe.

LNG reliance

Europe and the UK’s reliance on LNG imports is expected to increase over the next couple of decades as North Sea natural gas production declines. Stopping Russian imports via Ukraine will also drive up LNG reliance.

Rystad Energy projects that the EU’s reliance on LNG imports will grow from 38% in 2023 to 51% in 2040. If the emissions intensity of LNG imports does not improve, blue hydrogen producers face a significant challenge.

There are methane regulations in Europe and the US, alongside global commitments such as the Global Methane Pledge (GMP). Meanwhile, there is progress on remote monitoring technology, which will increase scrutiny over methane emissions across the global natural gas supply chain.

Nevertheless, according to DNV there are two things that the blue hydrogen industry must do to improve confidence in the reporting of emissions.

First, it must move to consistent reporting of emission intensities across the natural gas supply chain, as verified by third parties.

Second, clear reporting of the supply route, including country source, and how the natural gas was transported – whether via pipeline or LNG.

Credible solution

Meeting strict low emission thresholds is vital if blue hydrogen is to be a credible decarbonisation solution. Perhaps an even larger challenge is ensuring that blue hydrogen is competitive.

It’s first battle is against grey hydrogen. Later, as the technology improves and costs come down, green hydrogen will be vying for a piece of the action. Before we look at its longer-term prospects, let’s start with where things stand today.

ING estimates that the unsubsidised cost of producing blue hydrogen in North-Western Europe was ~€1.85 per kg in 2023. This is 15% more expensive than conventional grey hydrogen.

Green hydrogen is around three times more expensive than blue hydrogen.

The economics of hydrogen do not stand still. Several factors can have a major impact on both the relative and absolute competitiveness of grey, blue, and green hydrogen.

The most important factors include prices of gas, electricity, carbon, electrolysers. Meanwhile, capex and technological parameters also play a part.

Model moves

The Potsdam Institute for Climate Impact Research (PIK) have released a model where any individual can enter their own assumptions and see what it means for blue hydrogen versus green hydrogen.

Natural gas is the primary determinant of blue hydrogen production costs. PIK’s high gas price scenario assumes 60 euros (£51) per MWh in 2025. They then fall to 40 euros (£34) per MWh in 2030.

Meanwhile, their low gas price scenario assumes 15 euros (£12.8) per MWh throughout the period.

The analysis also includes two technology scenarios for blue hydrogen – conservative and progressive. These assume different carbon capture technologies and associated carbon capture rates, and methane leakage.

Meanwhile, green hydrogen production costs largely depend upon whether electrolysers are grid connected, when there are higher power prices and grid fees. Or off grid, with lower renewable energy costs.

Two technology scenarios for green hydrogen developed by PIK account for the cost of electrolyser, grid-connected versus off-grid, and the proportion of renewable power used, among other factors.

Cost changes

Recent research by BNEF highlights the challenge in anticipating technological progress decades into the future.

Declining prices are not a certainty. BNEF found the price of electrolysers in China, the US, and Europe increased by more than 50% over the past year.

The chart below shows the levelised costs and lifecycle GHG emissions intensity for green and blue hydrogen and natural gas. This is based on PIK’s base case assumptions. It shows that a low natural gas price environment could mean blue hydrogen stays competitive with green hydrogen through to the mid-2040s, even if green hydrogen reaches a progressive state of technological improvement.

This is potentially the scenario that awaits the UK and Europe if LNG supplies increase, and natural gas prices remain low, as many forecasters expect.

Levelised costs of production for hydrogen

Source: PIK

Carbon questions

However, we really need to think about the price of carbon. The fuel switching CO2 price (FSCP) is the carbon price when lower emission hydrogen become cost competitive with higher emission hydrogen.

The FSCP is a core indicator in regions – such as the UK, the EU, and elsewhere – that employ explicit carbon pricing or regulation that aims to reduce the emissions intensity of fuels.

Notably, ICIS’ price assessment for grey hydrogen rose higher than blue – on a project breakeven basis – for the first time in the first quarter of 2023. High carbon prices, of around 100 euros (£85) per tonne.

ICIS notes this meant it was “cheaper to invest in a gas based hydrogen production unit with CCS capacity than paying for the carbon emissions resulting from grey hydrogen”.

However, as carbon prices retreated over the course of 2023 – the price of EU emission allowances (EUAs) declined by ~30%. Meanwhile, UK allowances (UKA) dropped by ~55%. As a result, the grey hydrogen discount versus blue hydrogen returned.

Carbon goes up

Nevertheless, both UK and EU carbon prices are expected to rebound over the next couple of years. The supply-demand balance should tighten as emission allowances begin to bite.

UKA prices are forecast to almost triple by 2030. A recent report from Macquarie predicts they will move from £55 per tonne (65 euros) in 2023 to £152 per tonne (180 euros) in 2030.

PIK’s analysis also assumes that carbon prices reach 180 euros (£154) per tonne by 2030. They then rise to 280 euros (£239) per tonne by 2040 and to 390 euros (£333) per tonne by 2050.

What does this carbon price scenario mean for hydrogen switching? Despite this increase, green and blue are more expensive than grey until at least 2035, across all scenarios. Both blue and green require carbon prices of 200 euros (£171) per tonne by 2035 to be competitive with their more carbon intensive alternatives.

Furthermore, the blue hydrogen carbon and methane performance is crucial if it’s to remain competitive versus grey hydrogen.

Blue hydrogen with low carbon capture rates or high methane emissions, needs a very high carbon price to be competitive.

As discussed earlier, the main factor determining the competitiveness of blue hydrogen is the price of natural gas. If natural gas prices remain high compared to pre-energy crisis levels, at around 40 euros (£34) per MWh, the blue to green hydrogen switching point may have already passed.

However, if natural gas prices stabilise at the lower level of 15 euros (£12.8) per MWh and blue hydrogen can keep emissions low, the blue-to-green hydrogen switching points occur only after 2040.

Switching tracks

In the short to medium-term, blue hydrogen would be substantially cheaper than green hydrogen. This is despite its higher emissions. The declining cost of green hydrogen only brings it into the switching range around 2035-40.

Hydrogen switching points based on carbon prices

Source: PIK

Overall, blue hydrogen must navigate a narrow and uncertain path if it is to emerge as a supplier of low carbon hydrogen to the UK’s hard-to-abate sectors.

To their credit, the UK government has taken a more technology agnostic approach, compared with the EU. However, despite early progress in developing blue hydrogen capacity, the road ahead is still paved with obstacles.

First, blue hydrogen must be able to demonstrate that it meets demanding low carbon thresholds. This means investing in the latest blue hydrogen technology and continuing to decarbonise UK North Sea production.

Second, eventually the cost of green hydrogen will come down, and outcompete blue hydrogen. In the meantime, blue hydrogen will need further policy support from government in the form of higher carbon prices.

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