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How quickly can hydrogen help the UK get to Net Zero?


United Kingdom

Tipped by some to be the answer to cleaner emissions, hydrogen's potential role in the UK's energy future is complicated by questions about the cost and efficiency of production methods, storage options and use cases. Hugo Lidbetter, renewables specialist at Fieldfisher, examines the case for hydrogen.

  Hydrogen is a gas with limited industrial applications, mainly associated with the manufacture of ammonia and fertilisers.

However, the role it could play in a "Net Zero" UK energy mix has started to garner more attention.

Hydrogen is non-toxic and abundant in the forms of water and natural gas. When consumed it only releases water vapour.

It has the potential to replace natural gas and become a reliable means of storing renewable energy across seasons. It can also complement lithium-ion batteries as a fuel replacement for heavier vehicles, including lorries, ships and trains.

This becomes very important in the context of mounting environmental obligations.

2020 has already seen new EU emission performance standards for passenger cars and updated marine sulphur emission reduction requirements from the International Maritime Organization (IMO), as well as policy movements against conventionally fuelled vehicles (e.g. clean air zones in city centres including London, Leeds, Bristol and Birmingham). 

Hydrogen's potential was recognised by the Committee on Climate Change in its May 2019 Net Zero Report, which stated that:

"Moving beyond an 80% target changes hydrogen from being an option to an integral part of the strategy (…) By 2050, a new low-carbon industry is needed with UK hydrogen production capacity of comparable size to the UK's current fleet of gas-fired power stations."

National Grid echoed this view in its 2019 Future Energy Scenarios, noting:

"In our Net Zero sensitivity, there is an increasing reliance on hydrogen, which can be burnt without the release of carbon".
Two opportunities for hydrogen

1. At present, the production of hydrogen, almost all of which is through fossil fuels, consumes 6% of the global supply of natural gas and 2% of the global supply of coal.

The associated annual CO2 emissions from the production of hydrogen are equivalent to those of the UK and Indonesia combined. Cleaning up hydrogen production for its own sake is no small challenge, let alone exploring its potential as a major energy source of the future.

2. Hydrogen for industrial applications is almost entirely driven by steam methane reformation (SMR), as electrolysis consumes more energy than can be channelled into the hydrogen it produces.However, with the falling costs and growing penetration of renewable power, there has been considerable interest in exploiting hydrogen through green electrolysis.

Electrolysers co-located with renewable generation in the most favourable solar or wind locations (desert areas and far offshore environments) could open up cost savings from using cheap renewable power when demand is low or generation would otherwise be curtailed (e.g. due to network issues).

Producing hydrogen this way also provides an alternative means of storing and transporting energy from the point of generation to point of use, compared to storing electricity in batteries and transporting it through cables.
Producing hydrogen

There are two methods of producing hydrogen.

The first and dominant way is SMR – i.e., from the combustion of natural gas in steam.

The second method of producing hydrogen is by applying an electrical current to water in a process called electrolysis, which produces hydrogen and oxygen.

The SMR process produces what is known as "grey hydrogen", as it still has CO2 emissions associated with the combustion of natural gas.

To get to cleaner so-called "blue hydrogen", CO2 must be caught by carbon capture and storage (CCS) technology.

Scaling SMR in the future depends almost entirely on how successfully, and at what cost, CCS can be developed and combined with SMR.

The addition of CCS does not make SMR-produced hydrogen entirely carbon-free, however, as CO2 capture efficiencies are only expected to reach 90%.

Carbon capture pilot projects are at very early stages and are not yet performing anywhere near this level.

This suggests carbon capture technology, and therefore the viability of low-carbon SMR, will not scale up significantly unless capture rates, process efficiencies and long-term storage are all substantially improved.
Legal issues for SMR

From a legal and regulatory perspective, the main issue will be how power generators and industrial consumers of natural gas are compelled to incorporate expensive CCS technology.

This challenge is characteristic of the future use of natural gas more generally, not just the production of hydrogen.

The UK government is currently consulting on funding models for different parts of the CCS value chain, in recognition of different risk profiles and technological challenges in capturing, transporting and storing CO2.

As with the shift from coal in the 1990s, adoption of CCS technology is likely to be achieved through a combination of:

(i)           New or extended emissions-based legislation, analogous to the Industrial Emissions Directive (IED) and Large Combustion Plant Directive (LCPD); and

(ii)          Finance-based legislation, to create an economic incentive akin to the EU Emissions Trading Scheme (EU ETS) and Carbon Price Floor (CPF), which essentially shifted the marginal cost of generation in favour of renewables by making it more expensive for fossil fuel generators to operate.

A further regulatory issue concerns the long-term liability regime for stored CO2 after it has been captured, an issue that has parallels with the long-term storage of nuclear waste.

A robust inspection, verification and monitoring regime for both the capture and storage stages will be key to providing confidence in the investment case for CCS technology. Without a clear long-term policy framework, investors will be concerned they are investing in a stranded asset class.

Similarly, a new carbon market for the captured CO2, e.g. in synthetic fuels, could provide a positive revenue stream to the project, to complement its hydrogen offtake arrangements.

There are several different types of electrolysis, which differ depending on which catalyst is used – the main forms being polymer membrane electrolysis (PEM) and alkaline electrolysis.

At the moment, electricity for the process is generally sourced from the Grid (which will include a large proportion of fossil fuel-derived electricity), but the hope is that, over time, electrolysers will be powered by dedicated renewable energy (producing so called "green hydrogen").

The levelised cost of hydrogen (LCOH) for electrolysis is currently almost double that of SMR, mainly due to high electricity prices and slightly poorer efficiency levels of the electrolysers.

Given the multiples of additional renewable generation required to deliver Net Zero, there is a significant opportunity for electrolysis to capitalise on that renewable growth, although it is unlikely there will be sufficient renewable capacity to make the economics of electrolysis attractive until after 2030.

This is because the early phase out of the Feed in Tariff (FiT), Renewables Obligation (RO) and closure of the Contracts for Difference (CfD) auction to onshore wind and solar resulted in a significant cooling in onshore renewable investment in the UK over the last couple of years.

From an energy systems management perspective, electrolysers also have the potential to offer demand-side flexibility to National Grid, ramping production up or down in response to the varying availability and price of power.

This, along with the time-shifting of energy demand, provides a useful economic-based reaction to the intermittency of high volumes of renewable generation.
Energy storage

Once produced, hydrogen can either be stored as a liquid at extremely low temperatures (below -250°C) in dedicated structures (liquefaction), or as a compressed gas in large pressurised storage tanks or underground salt caverns (pressurisation).

Pressurisation offers the potential for long-term storage, possibly across seasons and, of the two, is probably more appropriate for the long-term storage of high volumes of hydrogen.

Unfortunately, both liquefaction and pressurisation come at the cost of significant energy losses: liquefying hydrogen and keeping it cooled below -250°C consumes huge amounts of electricity.

There is also the potential for more innovative storage solutions, for example, by converting hydrogen to energy-dense ammonia. This means the same volume of transported material can carry a higher density of stored energy.

As with liquefaction and pressurisation, ammonia synthesis and cracking also consume a large amount of energy.

The major economic advantage of developing hydrogen as a method for storing renewable power is that it can help smooth volatile energy prices in a renewables dominated energy mix.

It also provides greater energy security than relying on interconnectors or gas imports. Conversely, much like LNG, hydrogen has the potential to be a valuable tradable commodity, particularly from areas of favourable generation (Middle East and North Africa) to areas of high demand (Central Europe).
Legal issues for hydrogen storage

The transport and storage of hydrogen do not really present any new issues that do not already exist through the use of natural gas (e.g. in the gas transmission network and when stored in underground salt cavities).

In this respect, the safety regime is already well defined in the UK by the HSE – e.g. through the Gas Safety Regulations, Pipeline Safety Regulations and the Control Of Major Accident Hazards (COMAH) Regulations – all of which may require adaptation for hydrogen use in place of natural gas.

The technical challenges associated with conversion to hydrogen are already well understood.
Applications of clean hydrogen

Once a cost-effective solution to producing hydrogen at scale has been found, it has a number of potential applications to support the delivery of Net Zero:
  • Industrial: In principle, hydrogen could replace natural gas in energy-intensive industrial processes such as steel production.
  • Transport: For intensive long-haul vehicles, busses and trains; and in shipping and aviation, hydrogen may prove to be a more appropriate fuel than lithium-ion batteries. Germany already has hydrogen trains operating in some areas.
  • Power generation: Hydrogen presents opportunities to store renewable energy for longer than lithium-ion batteries and replace natural gas in gas turbines. This is important for maintaining the resilience of the electricity system and providing security of supply in an increasingly intermittent renewables-based generation mix.
  • Buildings: Almost 20% of greenhouse gas emissions in the UK are associated with heating residential space, mostly via natural gas in boilers (rising to around 30% for residential and industrial heating combined). There are a number of pilot studies looking at the extent to which hydrogen can replace or be blended with natural gas. Initial studies indicate that hydrogen can safely be blended to concentrations of up to 20% with natural gas without requiring any change to the existing gas network or customer appliances.
Hugo Lidbetter is a corporate partner specialising in renewable energy in Fieldfisher's Birmingham office.

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