Hydrogen is a colourless, odourless, and non-toxic gas. However, hydrogen doesn’t exist as such: it is produced or extracted with the help of various methods, which differ in the way they impact the environment.  

Depending on the extraction/production technology, hydrogen is either classified as ‘black/brown/grey’, ‘blue’, ‘green’ or ‘pink’:   

• Black, brown and grey hydrogen is produced through Steam Reforming (SR) or gasification, using natural gas or methane as the feedstock (grey) [1]. During this process, the feedstock is partially oxidised to produce carbon dioxide (CO2) and hydrogen (H2), with some waste heat. Black and brown hydrogen use more damaging fuels (different types of coal) and also do not recapture either the carbon dioxide (CO2) or monoxide (CO). Grey hydrogen production consumes approximately 6% and 2% of global gas and coal supply, emitting 830 mtCO2 annually, which equals more than 2% of global fossil CO2 emissions [2].
• Blue hydrogen offers a less environmentally damaging option. It uses the same feedstock and process as grey hydrogen, however, 80-90% of the CO2 produced is captured within the process and is typically stored underground through industrial carbon capture and storage (CCS) methods [1]. Importantly, this is neither sustainable nor renewable, because fossil fuels are still used within the process and some of the CO2 produced cannot be captured.
• Green hydrogen offers a renewable and sustainable method of generating this fuel, with few restrictions on the quantity available. Green hydrogen is manufactured through the electrolysis of water to produce both hydrogen and oxygen gas, using renewable energy sources. While having clear benefits, it is currently more expensive than the methods mentioned previously.
• Pink hydrogen is similar to green in that it involves the electrolysis of water using electricity, but with nuclear energy as the source. Although this method involves almost no carbon dioxide, a distinction is made between pink and green as nuclear energy is arguably sustainable but not renewable at the present time. 

The transport sector’s demand globally is substantial.  Within the UK, transport accounts for 33.5% of our total energy demand (37.9 Mtoe or 440.8 TWh) – 92.1% of this is sourced from hydrocarbons. Within this group of hydrocarbons, 229 TWh or 52% of the total sector’s energy demand in 2021 was attributable to road diesel [3]. 

Chart 1: UK transport sector Mtoe usage by sector

As you can see in Chart 1, there has been a large increase in diesel usage for the last 20 years due to the then dominating rhetoric that diesel is a cleaner fuel source than petrol.  We know today that this was false.  

Meanwhile hydrogen, specifically green hydrogen, can help reduce our reliance on fossil fuels, especially within the transport sector. This can be achieved in a number of ways:

1.     Fossil fuel refinement

Hydrogen is commonly used within the fossil fuel refining process to reduce the quantity of impurities (especially sulphur) within the fuel and to crack heavy oil fractions into lighter products. Oil refining is responsible for around 50% of the total demand of hydrogen globally, around 37 Mt. Approximately half of this is sourced from by-products elsewhere within the process chain, the other half is typically generated on-site using SR (grey hydrogen). This presents an opportunity for emission reductions using green hydrogen.

The demand for hydrogen used in the refining process is predicted to fall in line with the anticipated reduced demand for fossil fuels to meet announced pledges and net zero emissions scenarios. Oil producers therefore may see reduced benefit from investing in green hydrogen production due to the perceived increased risk of stranded assets [4].

2.     Renewable diesel

Biodiesel is a category of diesel products that are produced using renewable and organic feedstocks in combination with reactants to produce a near identical fuel to the hydrocarbon-derived alternative.

Two methods exist to create bio diesel: the first concerns more traditional biofuel, using an esterification process where methanol is consumed to esterify the biomass feedstock. This is known as Fatty Acid Methyl Esters (FAME) [5]. The second process consumes hydrogen to hydrogenate the biomass to produce a pure biofuel that has an identical chemical composition with fossil diesel. A common example is Hydrotreated Vegetable Oil (HVO), where the properties are very similar to sulphur-free fossil diesel (vs. FAME), including the ability to use the same analytical tools [6]. This type of biofuel has been described as a second-generation biofuel.

Both the hydrogen and the methanol required for the above processes have traditionally been produced from natural gas. However, there is the opportunity to use green hydrogen sourced from renewable energy to transition from biodiesel to renewable or green diesel [5]. This offers a sustainable and renewable fuel source that, assuming fully renewable energy is used during the process (including in the feedstock chain), is a net zero carbon fuel source.

Aside from the obvious benefits of using HVO compared to traditional diesel, there are other benefits when compared to FAME. These include:

• FAME fuel quality is dependent on the underlying feedstock and therefore limits the quality and type of biomass that can be used. For HVO, the feedstock can be similar or lower quality, although more parameters need to be measured.
• HVO has the highest specific heating capacity when compared to conventional biofuels i.e. it is the most energy dense (per volume and mass).
• With additional processing, HVO can still perform very well in temperatures as low as -50 °C. This allows for wider market appeal and the possibility of it being used in aviation.
• It has very good environmental characteristics, including very low aromatics, and is free from metals and ash-forming elements.
• HVO has very similar behavioural and handling properties compared to fossil diesel, which reduces any infrastructural and use case conversion requirements.

3.     Fuel cells

A conceptually easier and more widely discussed use of green hydrogen is to power vehicles directly via fuel cells. With this method, onboard stored hydrogen (gas) is combined with oxygen extracted from the atmosphere to create water and power, which in turn provides a small intermediatory battery energy from which to power an electric motor to propel a vehicle. The only ‘exhaust’ emission is water.

Proponents of this technology generally believe that battery electric vehicles (BEVs) are not a long-term, sustainable solution. A major reason for this is the quantity of rare earth metals and the associated environmental impact of extraction required for these batteries. Battery technology is advancing at a rapid rate however, within many different internal architectures and materials in development. Fuel cell electric vehicles (FCEVs) offer a cheaper, lighter and more sustainable approach using already established storage techniques and design philosophies.

The current issues with hydrogen mainly lie with the production and the supply side storage. The benefits of using FCEVs are greatly reduced if the source hydrogen isn’t green. However, almost all of the hydrogen produced is used within the chemical and refining industry (~93%) and is typically made on-site where the demand is situated. Currently, transport accounts for just 0.02% (20 kt) of hydrogen demand [4]. Even if green hydrogen production was abundant, the supply infrastructure does not exist – it is very much a chicken and the egg situation. Hydrogen vehicles do present a good technical solution, but while there are very limited refuelling stations (especially within the UK), this will not change without substantial investment in both the use cases and the infrastructure.

Overall, there are many opportunities for the transport sector to transition to low-carbon or zero-carbon solutions, with heavy-duty vehicles and logistics in general well positioned to take advantage of this technology: due to their size, heavy-duty vehicles are well suited for large hydrogen tanks, where the possible drivable range far exceeds current battery technology. Secondly, one of the inherent benefits of hydrogen is decentralised generation; this is a great option, especially for fleet-based vehicles with centralised hubs where these generating stations could be built, especially combined with onsite renewable generation. In addition, for haulage vehicles, it is likely that customers would be based in industrialised areas, which could provide a suitable place for hydrogen generation.

In 2020, oil, gas, and chemical company OMV invested around €200 million in biofuel production in its Schwechat Refinery. This resulted in a capacity to convert up to 160,000t of liquid biomass into carbon-neutral biofuels a year. By substituting fossil diesel with biofuels, OMV will reduce their carbon footprint by 360,000t.

In a next step to further reduce emissions, OMV signed a €25 million joint investment into a 10MW Polymer Electrolyte Membrane (PEM) electrolyser, which can produce up to 1,500 metric tons of green hydrogen a year. This is forecasted to reduce OMV’s carbon footprint by another 15,000 metric tonnes, meaning a ratio of 10:1 of carbon dioxide reductions to hydrogen generated (by mass) [7].

Assuming an efficiency of 65% of Lower Heat Value (LHV) (51.2 kWh/kg H2) for commercial electrolysers [8], we can calculate the uptime to be 87.7%. The yearly energy consumption is approximately 76.8GWh. This leads to an average carbon reduction intensity of 195 gCO2e/kWh (the amount of carbon emissions saved per unit energy which is used to generate the hydrogen). This leads to an interesting conclusion:

Chart 2: Carbon intensity for different countries & generation sources

The electricity used to produce green hydrogen must be from a renewable source, therefore it could either be fed into the grid or it could be used to produce hydrogen. If this renewable energy is fed into the grid, this would naturally offset electricity derived from fossil sources, therefore reducing carbon emissions. The carbon intensity emission per unit energy varies depending on the source of energy.

The calculated value of 195 gCO2e/kWh represents an electricity carbon intensity hurdle rate whereby, if a country’s carbon emission intensity is below this threshold, it is environmentally beneficial to use the renewable energy to generate green hydrogen (for use in FCEVs, biofuels, etc) compared to offsetting fossil generation of electricity. For countries with electricity generation above this value, greater emissions reduction can be achieved by purely supplying the grid with the renewable energy and offsetting fossil generation (Chart 2). This assumes that this renewable energy would offset high polluting generation sources like coal, oil and natural gas.

One example: within Austria, the average carbon intensity of electricity production is 81 gCO2e/kWh (2021) [9], therefore it is more likely to be beneficial to implement a green hydrogen strategy. Looking at the Netherlands, we have a different situation: the country has a carbon intensity of 329 gCO2e/kWh. Therefore, based on the assumptions above, feeding the renewable energy into the grid seems to be more environmentally beneficial in this case. These examples demonstrate that many factors need to be considered before implementing such a scheme – as what may seem to be the best solution may actually not be. 

The EU Taxonomy is a key component of the EU’s strategy for sustainable financing, aiming to encourage and align investments to meet the ambitious climate targets set out. Amongst other environmental objectives, much of its focus is to support climate change mitigation and adaptation. In February 2022 a separate piece of legislation, the Complementary Climate Delegated Act, was published to cover certain gas and nuclear activities [10]. This Delegated Act sets out conditions subject to which certain nuclear and gas activities can be added as so-called transitional activities (activities where there are no technological and economically feasible low-carbon alternatives)[11]. To meet the conditions, each gas-related activity must:

• meet specific emission thresholds,
• should replace an existing coal facility which cannot be replaced by renewables,
• should achieve certain targets in terms of emissions reductions,
• and fully switch to renewable or low-carbon gases by 2035.

Additionally, governance and reporting has been strengthened. For example, robust evidence should be available, ‘demonstrating that the same energy capacity cannot be generated with renewable sources, and that effective plans are put in place for each facility, in line with the best performance in the sector, to switch entirely to renewables or low carbon gases by a specific date [link].’

Looking at reporting, for example, companies and finance providers would have to disclose amounts of revenue generated from / invested in gas-related activities, as well as to which extent the activities meet the criteria under the Taxonomy and thus can be considered transitional.  To further enhance investor confidence, compliance with technical criteria will have to be externally verified by independent parties with the appropriate resources and capabilities.

While the Delegated Act has driven a renewed focus on natural gas as a fuel source to transition away from coal, critics comment that the current reliance on natural gas is responsible for much of Europe’s energy crisis, with imports of Liquified Natural Gas (LNG) having risen 65% in the first nine months of 2022 compared to 2021. The average transportation and storage carbon emissions per barrel of LNG is approximately 10 times higher than piped gas [12]. Therefore, encouraging investment in long term natural gas rather than renewables is irresponsible and will only deepen the reliance on fossil fuels, including imports.

A spokesperson for ClientEarth, WWF European Policy Office, T&E and BUND said [10]: "Propping up gas, a fossil fuel that is currently at the centre of a cost-of-living crisis across the bloc, undermines the EU's fundamental aims of achieving cleaner, cheaper and more secure energy. To bring down people’s bills, secure energy supplies and protect citizens from climate chaos, the EU needs to stop greenwashing gas as ‘sustainable’ in the EU Taxonomy.”

This policy decision tries to address the difficulty of transitioning to a net zero economy, recognising that even within Europe, economies and energy policies are at different stages of their decarbonisation journey. However, we are yet to see its implementation, which is unlikely to be easy, as well as whether investor appetite would ever shift to EU Taxonomy aligned fossil gas activities.

Chart 3: Hydrogen costs by generation type

It needs to be highlighted that the implications on hydrogen production are not completely black and white. Grey hydrogen does offer reduced emissions versus black/brown hydrogen which uses solid fuel sources, therefore grey hydrogen can be seen as comparatively environmentally beneficial and therefore would qualify under the taxonomy’s Article 10. The debate will mainly focus on the economic feasibility of using grey versus green hydrogen. Currently, the cost of green hydrogen is approximately $5 per kg, compared to grey at around $1.60 [14]. The somewhat loosely defined nature of economic feasibility will most likely distinguish investors’ motives.

Looking at the price, organisations could be tempted to pivot to blue hydrogen, with current costs of around $2 expected in 2025, with a 98% CCS rate – this would allow companies to achieve emissions targets at a lower cost than with green hydrogen. However, as pointed out earlier, blue hydrogen is neither sustainable nor renewable and hence should not be considered a permanent, long-term solution. 

The hydrogen economy is currently highly fragmented, providing multiple areas of opportunity for both new participants as well as those pivoting from associated industries:

• Generation: the general plant equipment needs to generate the green (or blue) hydrogen,
• Infrastructure: concerning both transport and storage requirements, both locally and nationally (in time),
• End use: mainly involving development in mobility technologies such as cars, goods vehicles, shipping and aviation. Also, higher blends (currently 0.1%) in gas feedstocks for residential properties; a 20% hydrogen blend is expected in 2028 (new boilers support this) [15],
• Renewable infrastructure: the renewable electricity source including grid investments,
• Grid energy storage and integration: serving to ‘balance’ the grid with high ramp rate systems and the possibility of generating/powering off-grid installations

Certain industries will be better placed to adapt to the evolving hydrogen economy. It is recognised that the fossil fuel industry will have to reduce considerably in line with net zero commitments. These companies may resist making investments into green hydrogen as they see a perceived risk with stranded assets [4].

From a client perspective, the pace of new developments within the governance and regulation of this sector may prove concerning or even a barrier to entry. Providing reassurance, risk management and expertise around all aspects of transitioning could be a great opportunity within the space. 

Both the production and uses of hydrogen need to be assessed and addressed as we move forward along the path of net zero commitments.

From a generation perspective, decarbonisation of generation is important. This will most likely be achieved through blue hydrogen in the short to medium term, followed by green hydrogen as economies of scale produce sufficient price reductions (Chart 3).

From a use case perspective, investment into infrastructure and technology will be central to developing the hydrogen economy. Oil and energy companies will play a key part, being well placed to utilise their key resources and capabilities within their current industry. For net zero emissions by 2050, it is expected that over 100 Mt H2 is required for transport alone – equivalent to the approximate entire current supply [4]. Using the values discussed within the case study section, to meet this expected demand by 2050, around 670 GW of installed capacity is required (assuming no efficiency increases).

In the short to medium term, it is uneconomical and unfeasible for the transport sector to switch a meaningful amount of diesel production to biomass-derived feedstock, however, replacing high-carbon hydrogen must become a priority; this is supported by the EU Taxonomy’s Article 10.