• Natural Gas News

    Opportunities And Challenges For Hydrogen In A Decarbonized Energy System


It is now well established that the way in which we produce, transform, and consume energy must fundamentally change over the coming decades if the Paris Agreement target of limiting global warming to well below 2°C is to be met and if we are to avoid dangerous climate change.


Posted in:

Complimentary, Natural Gas & LNG News, Global Gas Perspectives, Energy Transition, Hydrogen, Carbon

Opportunities And Challenges For Hydrogen In A Decarbonized Energy System

Fortunately, there is now substantial evidence regarding the broad features of future energy systems that might meet this target; the cornerstones of the transition are improved energy efficiency, power sector decarbonization, and electrification of as many energy end-uses as economically and technically practical (e.g. substantial parts of building heating and transport). This vision is already making significant headway in the form of rapid renewables uptake in the power sector and movements towards the electrification of large parts of the transport sector, and to an extent in heat provision.

In the 1990s and early 2000s, hydrogen was seen as playing a key role in the future of energy. It then lost favour as technological optimism was overcome by infrastructure, economic, and other concerns. But this is now changing, and hydrogen is back with renewed interest, helpful policy targets, and a range of credible companies offering products and services across the value chain.

Where does hydrogen fit in future energy systems?

Arguably the biggest success stories of decarbonization to date are those of solar photovoltaics (PV) and wind power. One does not need to look far in the literature or at on-the-ground uptake to see that this is true.

For example, in the case of solar PV, deployment has consistently exceeded expectations, and learning rates have been reducing capital cost by more than 20 per cent for each doubling of capacity. Similarly, for wind power, the success of offshore auctions in the UK has been spectacular, with prices dropping from around £ 120/MWh to less than £ 40/MWh in less than a decade. With these trajectories it is no surprise that solar PV and wind power are expected to make up a large portion of global power system capacity by mid-to-late century. This, combined with upbeat projections of end-use electrification of transport, heat production, and parts of industry is central to conventional wisdom on how to combat climate change.

But how far can the world go with such a strategy? While a number of prominent studies involving 100 per cent renewable power systems exist, the question of intermittency of solar and wind sources, and therefore system operability, cannot be overlooked. On this point, most studies of global decarbonization limit solar and wind uptake to 50–70 per cent of electricity production. This issue is further compounded by potential large-scale electrification of end-uses, changing the timing of demands and increasing the magnitude of demand peaks.

A good example of this is the coincidence of low wind, low sun, and high heat demand in winter in the UK. Notable examples of this were in January 2010 and January 2021. In such periods, if space and water heating demand were served by ubiquitous air source heat pumps, as is often proposed (and especially since heat pump performance drops in cold weather), very large excess electricity supply capacity may be required. Moreover, end-use electrification is not economically and technically viable in all sectors. Often-cited examples of this are aviation, heavy goods transport, and important parts of heavy industry.

Given these issues, it seems likely that something else, in addition to the fundamentals of power sector decarbonization and end-use electrification, is needed if the world is to reach Paris Agreement targets while maintaining a workable, diverse, and economically sensible energy system. This is where hydrogen can potentially play a role in the future.

Hydrogen has several attractive features, beyond the obvious of being perfectly clean-burning and a very common element (though often tied up inconveniently with other elements such as oxygen or carbon). Of particular importance are its useful features of relative transportability (e.g. compared to heat) and long-term storability. The latter point is advantageous for not only the intermittency issue described above, but also broader energy security and system resilience. And hydrogen appears to have both the technical and economic advantage for long-term storage. One recent study pointed out that while lithium-ion batteries are increasingly dominant in many storage applications, they will likely not be able to compete with hydrogen in long-duration applications, even in the long term.

Furthermore, hydrogen can be an important peak-shaving resource, providing very significant value to energy systems by avoiding the need for large amounts of backup, carbon-emitting peaking power-generation capacity. During cold snaps, for example, hydrogen could serve peak heat demand, or fill long-duration troughs in renewables supply, taking load off the power sector when capacity is stretched, thereby avoiding potentially enormous price spikes. The fact that such a role is of high value to the energy system (and thus to consumers) creates a conundrum for energy markets in that a per-kWh price for hydrogen may not make sense; rather, its value is measured in avoided cost of standby electricity generation capacity (i.e. electricity kW versus gas kWh).

Finally, but certainly not least importantly, hydrogen can play a significant role in otherwise hard-to-decarbonize applications. Industry is probably the best example of this, where technologies such as direct reduction of iron can use hydrogen, as can any process requiring heat at greater than about 100°C, the range at which a heat pump is more challenged to operate. Industry is also the one sector where hydrogen is already routinely used, particularly in refining and chemicals production, and is often also present on site anyway, due to its use as a process feedstock.

How might hydrogen be produced?

The next important question is where the hydrogen to serve future energy needs might come from. A colourful array of terms has emerged to describe the technology options, based on which form of primary energy they are derived from—black for coal, grey for gas, blue for gas with carbon capture and storage (CCS), green for renewable electricity via electrolysis, turquoise for gas via less-proven pyrolysis technology, and more.

The figure below shows the range of production sources of hydrogen in the future scenarios as presented in the 2018 IPCC (Intergovernmental Panel on Climate Change) special report on global warming of 1.5°C (IPCC SR1.5). For context, this is against a background of 500–600 EJ world final energy consumption, as presented in the recent Shell scenarios. The figure shows a story of rising fossil-based hydrogen production with CCS, becoming the largest source of H2 production by 2050. This is arguably mostly blue hydrogen, but the International Institute for Applied Systems Analysis database does not provide that detail, and the fossil source could vary from model to model. Green hydrogen (hydrogen from electricity) then takes over, dominating the market by 2100, though the outliers on both the fossil-based and green hydrogen sub-plots should be noted; there is substantial disagreement between some models at such long time frames.

From these scenarios we can conclude that both blue and green hydrogen could be important in the coming decades, and it is not a simple case of ‘green versus blue’. In fact, the dominant form of production may well vary between locations according to natural endowments, proximity to demand, proximity to viable CO2 geo-sequestration sites, and other factors such as policy and regulation.

Despite uncertainty about future production routes, and arguably similar environmental and long-term cost credentials of each, recent policy in the EU has focused on green hydrogen. The EU Hydrogen Strategy prioritized green hydrogen by setting ambitious electrolyser capacity targets of 6 GW and 40 GW in 2024 and 2030, respectively. This is a bold move, supporting a technology that is currently less mature and more expensive over the more proven technology of steam methane reforming. It may pay off, if the cost of electrolyser technology can follow a trajectory similar to that of solar PV and wind power, as described above. It is possible, though not guaranteed, that green hydrogen can become cost-competitive with any other option far sooner than expected.

What factors impact on the role for blue hydrogen?

While green hydrogen is at present well supported by EU policy, the future of blue hydrogen is less certain. What are the main conditions for blue hydrogen to play a role?

Given that hydrogen production from gas is relatively mature technology, it is the CCS part of the supply chain that requires the most attention. There are an increasing number of CCS projects worldwide. However, several key elements are still lacking: scale of activity, development of one-size-fits-all technology, and plug-and-play policy. Without such things, it is hard to imagine a future that might put CCS on a path equivalent to that taken by solar PV and wind power over the last 15 years. This is particularly true in the UK, where the first and second attempts at kick-starting CCS failed, with the cited reasons being cost concerns, difficulty in guaranteeing (in the insurance sense rather than the technical sense) that the CO2 would stay underground, and ultimately well-founded concerns regarding continuity of government support.

Broadly speaking, if blue hydrogen is to become a major player in global energy systems, far-reaching success is also needed with CCS. This aligns blue hydrogen technology with other CCS-entwined technologies such as bioenergy with CCS and directair carbon capture and storage (DACCS). The former, and increasingly the latter, are seen as critical for achieving climate change mitigation ambitions, so it is a wonder that more effort is not directed at the success of CCS, whilst variable renewable energies race ahead.

Methane emissions are the second key issue for blue hydrogen. Methane emissions related to the oil and gas supply chain are estimated by the International Energy Agency Methane Tracker at 70 MtCH4/year, roughly equivalent to the entire energyrelated emissions of the EU in terms of CO2 equivalence. These methane emissions have become a key issue for the gas industry in recent years, and are now the subject of forthcoming regulation in the EU, with publication of an EU Methane Strategy in 2020. Like any technology related to fossil fuel supply chains, the embodied emissions in blue hydrogen may be significant, and may prove difficult to abate sufficiently despite concerted efforts by industry.

Finally, should methane emissions be dealt with, it is also clear that high-capture-rate CCS processes will be required to produce blue hydrogen. In this respect it is important to investigate technology beyond steam methane reforming with CCS, which requires capture from two streams (process and heat generation). Auto thermal reforming and methane pyrolysis are both interesting options in this regard, with the former relatively well established and the latter in development and early demonstration. Achieving a capture rate above 95 per cent, ideally close to 99 per cent, will be important for this technology in the future.


The weight of evidence suggests that hydrogen has a fighting chance at a role in future energy systems. This role may be bigger than long-term modelling under the auspices of the IPCC may suggest. Not all of the underlying integrated assessment models in such studies have full representation of hydrogen value chains, from supply through transformation and transition to the full range of end uses. Should this be consistently included, it is plausible that a much greater potential role for hydrogen would present itself.

The features of hydrogen, particularly its potential for long-duration storage and transportability, make it a solid zero-emissions partner to variable renewable energy. Hydrogen would likely have on-tap availability to serve peak demands, and the related supply chain can both consume and produce electricity, heat, motive power, and other services to complement zero and netnegative carbon electricity systems.

The thermal and energy density features of hydrogen also make it a good option for otherwise hard-to-decarbonize applications. Industry, heavy transport (and potentially aviation), and long-term storage applications are prime candidates.

Overall, hydrogen has similar inter-sectoral features as zero-carbon electricity; it can be used in multiple applications in multiple sectors with no end-use emissions, making it ripe for economies of scale across these sectors and benefitting from the lack of correlation of the demands between them. A decade ago, natural gas may have been the cost-effective partner to renewables; but new developments, not least the Paris Agreement, mean that hydrogen should be considered as an alternative. Time will tell. The priorities for now are to support innovation, demonstration, and deployment of hydrogen supply chains while also supporting a range of other technology options to achieve climate change mitigation.

Originally published by the Oxford Institute for Energy Studies.

The statements, opinions and data contained in the content published in Global Gas Perspectives are solely those of the individual authors and contributors and not of the publisher and the editor(s) of Natural Gas World.