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What’s All The Hype about Hydrogen?

By Erin Whitney
July 29, 2022

Hydrogen is getting a lot of hype these days.  In 2021, the U.S. Department of Energy issued a “Hydrogen Shot,” similar to the country’s ambitious moon shot half a century ago — seeking to reduce the cost of clean hydrogen to $1 for 1 kilogram in one decade [1]. The price of clean hydrogen is several times that right now. And global investment in the production of hydrogen and hydrogen carriers has skyrocketed. According to the International Energy Agency 2021 Global Hydrogen Review, the “global capacity of electrolysers, which are needed to produce hydrogen from electricity, doubled over the last five years to reach just over 300 [megawatts] by mid-2021. Around 350 projects currently under development could bring global capacity up to 54 [gigawatts] by 2030. Another 40 projects accounting for more than 35 GW of capacity are in early stages of development. If all those projects are realised, global hydrogen supply from electrolysers could reach more than 8 [megatonnes] by 2030.” [2]

So, why hydrogen, why now, and what is its relevance to microgrids and Alaska? Well, let’s take a step back to understand how hydrogen fits into the energy economy and landscape.

Hydrogen has long been discussed as a potential energy panacea. Electrolysis was discovered and the first fuel cells were developed in the early 1800s. And General Electric produced hydrogen fuel cells to generate electricity for the Apollo and Gemini space missions in the 1960s.  

In 2006, my first research assignment after graduate school at the National Renewable Energy Laboratory investigated vehicular hydrogen storage via physical adsorption into porous solid materials. The materials couldn’t store nearly enough hydrogen to make them an economical storage solution at the time. As national political administrations came and went, both before and after that, so also did the buzz about hydrogen.

And here we are now in 2022. With a looming climate crisis, driven by rising global carbon dioxide levels, but also accompanied by plunging costs of renewable energy sources, there may be an economical path forward not just for hydrogen but for renewably produced clean hydrogen. While the volumetric density of hydrogen is low relative to other fuels, its specific energy — by mass — is high. In other words, that little hydrogen molecule packs a punch, but it requires large volumes to store and deliver. It has immediate potential to help clean up the hard-to-decarbonize sectors of industrialized society, including steel, cement and fertilizer manufacturing. These industries use massive quantities of hydrogen and are currently huge contributors to global carbon dioxide emissions, in large part because the hydrogen is generated from fossil fuels. 

Hydrogen also straddles varied energy generation and usage pathways. It can be made from energy sources, both traditionally from fossil fuels as well as through electrolysis with renewably generated electricity. It can be used directly for a variety of energy applications, including electricity (combusted or used in fuel cells), heat (added to natural gas) and transportation (fuel cell vehicles). It can also be transformed into carrier fuels such as methanol, ammonia and synthetic hydrocarbons, which have wide application worldwide. So, producing renewably generated hydrogen has the potential to clean up large swaths of our energy landscape.

For microgrids in Alaska and the Arctic, hydrogen could present a way to use and marketize stranded renewable energy assets, either for long-term energy storage or export for use in the global hydrogen economy. In particular, as a long-term energy storage medium, hydrogen might help alleviate some of the energy concerns for Alaska communities by storing cheaper, locally produced energy on timescales longer than what are achievable with chemical batteries. 

I’ll admit I love the idea of using Alaska’s abundant summer solar resource to generate enough energy to produce hydrogen for communities’ long, cold winters. But is that possible? Let’s consider a community of a couple thousand residents with a ~9,000 megawatt-hour wintertime electric load — assuming a 3MW load on average for an approximate time period of four months between November and February. If 25% of that load is currently served by wind during that period, for example, there are still 6,750 MWh that are not covered by renewables and likely served by a diesel generator. At current energy prices of up to $1/kilowatt hour, that’s a multi-million dollar expense for that community to serve the remaining load with diesel generators.

As an extreme example, how much hydrogen would we need to supply all of that 6,750 MWh community load?  Well, a kilogram of hydrogen nets about 16 kWh of electricity from a 50% efficient fuel cell/inverter system [personal communication]. Therefore, 6,750 MWh would require over 400,000 kilograms of hydrogen if that were the sole energy alternative for the community. 

From there, we can estimate how much energy we’d need to produce 400,000 kilograms of hydrogen.  Production of 1 kilogram of hydrogen requires ~55 kWh of electric input. So, 400,000 kilograms of hydrogen would require about 5 MW of additional generation, assuming a six-month summer production period. To put this in perspective, there are currently a few ~0.5 MW-sized solar photovoltaic arrays in remote Alaska communities, so this production would have to scale up considerably. 

We also have to consider the storage requirements for this much hydrogen. We can gain some understanding of this investment with the assumption that gaseous hydrogen storage vessels run $1,000-$2,000 per kilogram [personal communication]. This figure would put storage alone of this quantity of hydrogen in the hundreds of millions of dollars. Compressing it to liquid hydrogen could be one alternative, and converting it to methanol or ammonia or another carrier fuel present additional options. The volumetric densities of methanol and ammonia are a little less than half that of diesel, so one could imagine doubling or tripling current diesel fuel storage capacities for winter electric load, all other things being equal. All of these pathways would decrease storage requirements, and methanol and ammonia could be stored much like conventional fuel, eliminate the need for compressed gas storage and potentially be used in combustion engines directly. On the other hand, green methanol (CH₄) requires a source of carbon dioxide, and ammonia (NH₃) requires a source of nitrogen. 

All of this is to say that hydrogen as a seasonal energy storage medium is a pretty big investment. And we haven’t even considered heating requirements and uses for a community.

Stepping back for a moment from an all-or-nothing hydrogen scenario from solar resources, one might imagine hydrogen produced from excess power and then supplying power for a shorter time period. As an example, for a 3 MW average load, 8 hours of consistent power would require 24,000 kWh, or ~1500 kilograms of hydrogen.  Storage costs would put this at several million dollars, which could be compared with current chemical battery costs and capabilities. We’re modeling those scenarios currently and are getting promising preliminary results and nontrivial savings. But there is lots more work to do to compare technologies and economics. 

Where do we go from here? Europe is arguably leading the charge in these efforts and provides some examples we can learn from. While there are currently no examples of microgrids with full seasonal storage, examples of microgrids with hydrogen storage over a few days or weeks include a project in the French territory of La Réunion Island in the Indian Ocean (SAGES), as well as a research microgrid at the scale of a few kW with hydrogen storage and cogeneration using fuel cell heat in French Polynesia (RECIF) [3,4]. 

In Scandinavia, on the northern coast of Norway, the HAEOLUS project is demonstrating the use of large-scale stranded wind assets to generate hydrogen for export [5]. Europe also hosts a network of hydrogen fueling stations for transportation, and cities across Europe are investing in hydrogen-powered fleet vehicles. The Fraunhofer Institute in Freiburg, Germany, is successfully piloting a hydrogen-natural gas blend for heating in one of the city’s neighborhoods. And the global shipping giant, Maersk, announced in the last year that it is switching to green methanol to decarbonize its operations [6]. 

Driven by the European Union’s ambitious goal, before the Ukraine war, to generate hydrogen for less than €2 per kilogram by 2030, widescale mandates are catapulting investment in massively scaled (gigawatts!) renewable power plants for hydrogen production. Many of these investments and developments are in nearby northern Africa, where there is plentiful land and sun for solar plants. As countries scramble to shift away from Russian natural gas supplies for electricity and heat, the economics of hydrogen have become even more attractive. For example, grey hydrogen produced from fossil gas now has a levelised cost of $6.71/kilogram in the EMEA [Europe, the Middle East and Africa] region, compared to $4.84-6.68/kilogram for renewable H₂, according to a BNEF study entitled “Ukraine War Makes Green Hydrogen Competitive” [7].

It is my belief that these massive-scale hydrogen generation plants will pave the way for smaller systems like Arctic microgrids by rapidly driving down the cost of hydrogen production components in the next several years, most notably electrolyzers, which typically cost on the order of $1.25 million per MW uninstalled for PEM electrolyzers [personal communication]. A Rethink Energy report, entitled “Hydrogen to Clean Up Energy with $10 Trillion Spend,” predicts that electrolyzer costs per unit will fall by 14% every time global manufacturing capacity doubles [8]. 

Building on the roughly 0.3 GW of electrolyzers that the International Energy Agency counts around the world currently, EU climate policy chief Frans Timmermans expects the EU and its neighbors to surpass a target to install 40 GW and a further 40 GW in other countries to the east and south by 2030 [9]. That means that electrolyzer costs should tumble dramatically in the very near future. We haven’t hit the sweet spot yet for hydrogen as a long-term energy storage medium for microgrids in Alaska, but I believe the near-term prospects are promising — thanks, in part, to these global efforts. 

As projection tools, there is also increasing emphasis on the development of models that take into account the actual operational states of electrolyzers and control systems (ramp up and ramp down times, etc.), among other hydrogen system components. There are lots of other factors we haven’t covered as well, like safety and flammability, but those are beyond the scope of this post. It’s an exciting time to be thinking about hydrogen and its possibilities!