Since I launched this dedicated posting site www.innovating4energy.com, in December 2019, specifically around innovating in energy, I have written 80 plus posts. Each post was undoubtedly a fundamental learning point for me as I attempted to dive deeper into the topic.

Within this, Hydrogen has been one of the main contributors. Including this post, I have written about different aspects of Hydrogen over ten posts, but most were during 2020.

Posts (with links) have covered Hotter Shades of Hydrogen, Tensions and Bottlenecks and Concerns, Show me the Electrolyzer, Hydrogen is the Big Ticket Needing a Landscape View,

Also, Has Hydrogen got the necessary gas, Massive Doses of Hydrogen Reality, Hydrogens Promise, Believing in Hydrogen and how Plug Power is the Apple of Hydrogen?

Then I suddenly “went off the boil” on Hydrogen. I felt a sense of hijack from the Oil & Gas Majors and the Equipment Suppliers, all pushing hard the interim solutions blending different gases for offering blue Hydrogen as the necessary bridge, over the next ten years or so.

I felt a sense of “lock into” as the investment to purchase gas generating assets and infrastructure can run for thirty or more years. That’s not interim or intermediate and is likely to stay blue as CCUS will get added on at the later stage as the logical option to complete a ROI on this “interim” decision

Then we had considerable commitments in project money from Governments, all claiming the chance to be a world leader in Hydrogen and race to Hydrogen dominance. So this race took hold, the equivalent of a gold rush, the hydrogen rush. Vast sums of money suddenly were caught up in multiple startups, experimentations and small pilot-scale projects, all needing building, validation and proving they “might” scale.

Lobbying has accelerated by the Majors and all with a vested interest in holding onto the status quo and pushing the building of interim solutions can provide the transition answers. They are, in my opinion, “wriggling on the stick on where their existing solutions were getting caught up in the wrong side of the energy transition ” Attempting to sell power generation solutions for example that had thirty to forty-year lifecycles is not interim.

These significant sets of activities began to distort well laid out plans for the hydrogen journey. It gave a period of reasonably intensive (seemingly daily) announcements that confused me more than helped. So I thought, let us leave this for a while. It just has to sort itself out, one way or another as it does seem Hydrogen is becoming a “free for all, grab a piece” and not a structure evolving transition that we really need.

So after nearly nine months, I am back, looking to bring my thinking about Hydrogen back on track for the current and future understanding.

Wood MacKenzie kicked started this with Hydrogen production costs: is a tipping point near., indicated that green hydrogen production costs will equal fossil fuel-based H2 by 2040. Nearly twenty years of ramping up Hydrogen to bring into its potential contribution to building a sustainable energy system.

Then IEA has recently provided an excellent update report, “Global Hydrogen Review 2021“, and it brings me back to wanting to re-engage with Hydrogen after this short break.

The top line summary is

• After several false starts, a new beginning around the corner
• Hydrogen suppliers are becoming cleaner……..to slowly
• Expanding the reach of hydrogen use
• Governments need to scale up ambitions and support demand creation
• Low-carbon Hydrogen can become competitive within the next decade
• Meeting climate pledges require faster and more decisive action.
• More vital international co-operation: a key leaver for success.

The IEA policy recommendations for the near term are:

• Develop strategies and roadmaps on the role of Hydrogen in energy systems
• Create incentives for using low-carbon Hydrogen to displace fossil fuels
• Mobilize investment in production, infrastructure and factories
• Provide strong innovation support to ensure critical technologies reach commercialization soon
• Establish appropriate certification, standardization and regulations

A page covers these top-line summaries and policy recommendations that give you the detailed thinking behind these by following this link to the Executive Summary page.

The IEA report provided a fairly comprehensive report on how the Electrolysis deployment is progressing. To quote:

“Water electrolysis is an electrochemical process that uses electricity to split water (H2O) into Hydrogen (H2) and oxygen (O2). In 2020, this process accounted for ~0.03% of hydrogen production for energy and chemical feedstocks.27 Of installed global electrolyzer capacity of 290 MW, more than 40% is based in Europe with the next-largest capacity shares in Canada (9%) and China (8%).

Four leading electrolyzer technologies exist today: Alkaline, proton exchange membrane (PEM); solid oxide electrolysis cells (SOECs); and anion exchange membranes (AEMs) (see Emerging Technologies below for more on SOECs and AEMs). Alkaline electrolyzers dominate with 61% installed capacity in 2020, while PEMs have a 31% share. The remaining capacity is of unspecified electrolyzer technology and SOECs (installed capacity of 0.8 MW).”

The rising concerns of PEM Electrolysers precious metals is a growing worry. Current materials for electrode catalysts (platinum, iridium), bipolar plates (titanium) and membrane materials are expensive, and presently overall costs for PEMs (USD 1 750/kW) are higher than for alkaline electrolyzers (USD 1 000-1 400/kW). Additionally, PEM systems currently have a shorter lifespan.

The technology challenges to bring down costs and resolve technologies that make up the final hydrogen solution are formidable and can have a twenty-year need to be fully resolved.

We do have an inevitable reality in our deployment. It is not going to scale or giving the needed scale!

In the optimistic tone of IEA comparing their Net-zero Emissions Scenario, capacity requirements in 2030 are 850 GW, some nine times the project pipeline when including early development stages. Despite such significant gaps, current efforts are a sound basis for expanding and accelerating deployment, raising ambition as new projects are developed. More countries build Hydrogen into their national strategies.

The point might become one where the alkaline electrolyzers begin to push the PEM electrolyzer out to the competitive race unless the breakthroughs in technology, scale, and costs are not realized, in PLM in the next few years.

China might hold the key.

As the IEA report states, in 2020, costs fell within the range of USD 1 000-1 750/kW (including electric equipment, gas treatment, plant balancing, and engineering, procurement and construction [EPC]). The lower cost is applying to alkaline electrolyzers produced in China, and the upper representing PEM electrolyzers.

The cost of alkaline electrolyzers in China – USD 750-1 300/kW, with some sources reporting as low as USD 500/kW29 – falls well below the average of USD 1 400/kW in the rest of the world.

Concerns over the reliability and durability of Chinese electrolyzers have been raised in the past, and manufacturing is improving quickly. As recently as a few years ago, Chinese manufacturers had to import several components, limiting their ability to reduce costs through industrial clustering and economies of scale. Local component manufacturing is expanding, however, so cost savings should for Chinese electrolyzers be realized soon.

The critical observations from the IEA report are as follows (quoting directly from the report on Hydrogen supplies, deployment and speed.

The cumulative capacity deployment of projects under construction
and planned would reduce capital expenses by almost 60% by 2030.

Shortfalls in electrolysis manufacturing capacity could impede the deployment of all projects currently under development, which could derail long-term government climate ambitions.

Global electrolysis manufacturing capacity was ~3 GW/yr in 2020, with alkaline designs accounting for 85% and PEMs for less than 15%, plus some minimal, artisanal manufacturing of SOECs and AEMs.

The most significant shares of manufacturing capacity are in Europe (60%) and China (35%). Interest in the technology is growing among significant companies such as Thyssenkrupp, Nel Hydrogen, ITM, McPhy, Cummins and John Cockerill, all of which have announced plans to expand their manufacturing capacities. (I thought Siemens was a major player here, surprising not being mentioned).

If all announced expansions are realized, manufacturing capacity could reach ~20 GW/yr, with process automation or improved procurement driving down manufacturing costs.

A dedicated industrialized supply chain and a corresponding industrial supplier landscape will be essential to meet capacity demands to 2030 and beyond. If available soon, this manufacturing capacity could meet the deployment needs of the current pipeline of projects and government pledges (an average of 6-8 GW/y from 2022 to 2030) and approach.

Increased electrolyzer production will affect demand for minerals, particularly nickel and platinum group metals (depending on the technology type). While alkaline electrolysis does not require precious metals, current designs use 800-1 000 t/MW nickel.

Even if alkaline electrolysis dominates the market by 2030, in the Net zero
Emissions Scenario this would entail a nickel demand of 72 Mt (much lower than the amount needed for batteries).

The catalysts in PEM electrolyzers require 300 kg of platinum and 700 kg of iridium per GW. Therefore, if PEMs supplied all electrolyzer production in 2030 in the Net-zero Emissions Scenario, demand for iridium would skyrocket to 63 kt, nine times current global production.

Experts believe that demand for both iridium and platinum can be reduced by a factor of ten in the coming decade. Recycling PEM electrolyzer cells can further reduce primary demand for these metals and be a core element of cell design.

Meanwhile, SOEC production requires nickel (150-200 t/GW), zirconium (40 t/GW), lanthanum (20 t/GW) and yttrium (<5 t/GW). Better design in the next decade is expected to halve each of these quantities, with technical potential to drop nickel content to below 10 t/GW. Due to the higher electrical efficiency of SOECs, these mineral requirements are not directly comparable with alkaline and PEM electrolyzers.

I wrote about “Will critical Mineral Supplies Stop The Energy Transition“, asking will supply be resilient and robust. Securing these critical minerals at economical prices at a time resource quality is becoming a growing concern as well will be making the Energy Transition even trickier to manage.

Hydrogen holds promise, but it is signalling high risk at present

I relate to some of my previous fears, discussed in the articles shown above, with their links.

PEM and Alkaline might be today’s runners for Hydrogen, but the IEA report rightly points out there are other production technologies of the future that hold promise. Let me quote from the report again on the four contenders.

Solid oxide electrolyzer cells (SOECs)

These are still in the demonstration phase for large-scale applications.

SOECs use steam instead of water for hydrogen production, a fundamental departure from alkaline and PEM electrolyzers. Additionally, as they use ceramics as the electrolyte, SOECs have low material costs. While they operate at high temperatures and with high electrical efficiencies of 79-84% (LHV), they require a heat source to produce steam.

Therefore, if SOEC hydrogen were used to produce synthetic hydrocarbons (power-to-liquid [PtL] and power-to-gas [PtG]), it would be possible to recover waste heat from these synthesis processes (e.g. Fischer-Tropsch synthesis, methanation) to produce steam for further SOEC electrolysis. Nuclear power, solar thermal and geothermal heat systems, and industrial waste heat, could also be heat sources for SOECs.

Methane pyrolysis

Methane pyrolysis (also known as methane splitting, cracking or decomposition) converts methane into gaseous Hydrogen and solid carbon (e.g. carbon black, graphite) without creating any direct CO2 emissions. The reaction requires relatively high temperatures (>800°C), which can be achieved through conventional means (e.g. electrical heaters) or using plasma.

Per unit of Hydrogen produced, methane pyrolysis uses three to five times less electricity than electrolysis; however, it requires more natural gas than steam methane reforming.

The overall energy conversion efficiency of methane and electricity
combined into Hydrogen is 40-45%. Notably, the process could create additional revenue streams from selling carbon black for use in rubber, tyres, printers and plastics. However, the market potential is likely limited, with global demand for carbon in 2020 being 16 Mt of carbon black, corresponding to hydrogen production from pyrolysis of 5 Mt H2. Carbon from pyrolysis could be used in other applications such as construction materials or replace coke in steelmaking.

Anion exchange membranes (AEMs)

AEM electrolysis combines some of the benefits of alkaline and PEM electrolysis. Using a transition metal catalyst (CeO2-La2O) does not require platinum (unlike PEM electrolysis). A key advantage is that the anion exchange membrane serves as a solid electrolyte, avoiding the corrosive electrolytes used in AEL. AEM technology is still at an early stage of development (TRL 4-5), but Enapter (Germany) is developing kW-scale AEM electrolyzer systems combined to form MW-scale systems.

Electrified steam methane reforming (ESMR)

SMR is a widely used process to produce Hydrogen from natural gas,
and SMR can be combined with CCUS to reduce CO2 emissions. To
achieve capture rates of 90% or higher, CO2 capture needs to be
applied to two gas streams: the synthesis gas stream after the steam
methane reformer (characterized by relatively high CO2
concentrations) and a more diluted flue gas stream caused by steam
production from natural gas. Because the latter has a lower CO2
concentration, capture requires more energy.

The technology has been demonstrated at only the
laboratory scale (TRL 4) to date, but a pilot plant is under construction
to use biogas as a feedstock in ESMR to produce Hydrogen and
carbon monoxide, which will then be converted into methanol.

Will these emerging technologies accelerate and become real competitors? They all have some technology or value in how they are made up to get to potentially competitive points, providing they can go beyond small scale into demonstrating the ability to be scaled.

The IEA lays out a plea or journey for Hydrogen.

The IEA’s Net-zero by 2050 roadmap (of IEA) shows that achieving net-zero targets will require immediate action to make the 2020s the decade of clean energy expansion through massive deployment of available low-carbon technologies and accelerated innovation of those still under development.

Hydrogen technologies are a crucial example, with a considerably higher pace of progress and deployment required from now until 2030 is needed.

The three overarching goals are to significantly expand hydrogen use while bringing new technologies onto the market; make hydrogen production much cleaner (i.e. shift away from unabated fossil fuel-based routes), and reduce the costs of technologies for hydrogen production and use.

All of these three overarching goals need a more coherent, extensive push, allowing the markets to evolve in the present fashion is not the ideal way to bring clean Hydrogen (green specifically) and cost of those technologies down without a greater concentration of efforts in the R&D labs, by Government targeted support. Collaborative environments to drive towards green hydrogen solutions that can cost-effectively take out fossil fuel alternatives.

If we do not bring all the parts together, then Hydrogen will not play the part within the Energy Transition it is expecting to play.