## MITEI study finds hydrogen-generated electricity is a cost-competitive candidate for backing up wind and solar

##### 29 August 2021

A team at MITEI (MIT Energy Initiative) has found that hydrogen-generated electricity can be a cost-competitive option for backing up wind and solar. In a paper published in the journal Applied Energy, they report devising a methodology to estimate the levelized cost of energy (LCOE) of meeting the seasonal nature of variable renewable energy (VRE) resources with either a hydrogen-fired gas turbine (HFGT) or lithium-ion battery system (LI).

Applying the model, they found that the average LCOE associated with meeting this seasonal imbalance is $2400/MWh using a HFGT fueled with green hydrogen and$3000/MWh using a LI. If the HFGT operates with blue hydrogen, the average LCOE decreases to $1560/MWh. However, the authors noted, the power prices required to justify investment in an HFGT to replace a natural gas-fired gas turbine are considerably higher than those seen in the market today. Because VREs such as solar and wind power produce electricity only when the sun shines and the wind blows, they need back up from other energy sources, especially during seasons of high electric demand. Currently, plants burning fossil fuels, primarily natural gas, fill in the gaps as peaker plants—a tendency that is likely to grow pari passu with VREs. As we move to more and more renewable penetration, this intermittency will make a greater impact on the electric power system. If we’re to achieve zero-carbon electricity, we must replace all greenhouse gas-emitting sources. —Emre Gençer, co-author Low- and zero-carbon alternatives to greenhouse-gas emitting peaker plants are in development, such as arrays of lithium-ion batteries and hydrogen power generation. But each of these evolving technologies comes with its own set of advantages and constraints, and it has proven difficult to frame the debate about these options in a way that’s useful for policy makers, investors, and utilities engaged in the clean energy transition. Gençer and Drake D. Hernandez devised a model that makes it possible to pin down the pros and cons of peaker-plant alternatives with greater precision. Their hybrid technological and economic analysis is based on a detailed inventory of California’s power system. While their work focuses on the most cost-effective solutions for replacing peaker power plants, it also contains insights intended to contribute to the larger conversation about transforming energy systems. Our study’s essential takeaway is that hydrogen-fired power generation can be the more economical option when compared to lithium-ion batteries—even today, when the costs of hydrogen production, transmission, and storage are very high. —Drake Hernandez California draws more than 20% of its electricity from solar and approximately 7% from wind, with more VRE coming online rapidly. This means its peaker plants already play a pivotal role, coming online each evening when the sun goes down or when events such as heat waves drive up electricity use for days at a time. Selecting 2019 as their base study year, the team looked at the costs of running natural gas-fired peaker plants, which they defined as plants operating 15% of the year in response to gaps in intermittent renewable electricity. In addition, they determined the amount of carbon dioxide released by these plants and the expense of abating these emissions. Much of this information was publicly available. Coming up with prices for replacing peaker plants with massive arrays of lithium-ion batteries was also relatively straightforward. Nailing down the costs of hydrogen-fired electricity generation, however, was challenging. The team considered two different forms of hydrogen fuel to replace natural gas, one produced through electrolyzer facilities that convert water and electricity into hydrogen, and another that reforms natural gas, yielding hydrogen and carbon waste that can be captured to reduce emissions. They also ran the numbers on retrofitting natural gas plants to burn hydrogen as opposed to building entirely new facilities. Their model includes identification of likely locations throughout the state and expenses involved in construction of these facilities. While certain technologies worked better in particular locations, we found that on average, reforming hydrogen rather than electrolytic hydrogen turned out to be the cheapest option for replacing peaker plants. —Emre Gençer Gençer said it was kind of shocking to see that there was a place for hydrogen, because the overall price tag for converting a fossil-fuel based plant to one based on hydrogen is very high, and such conversions likely won’t take place until more sectors of the economy embrace hydrogen, whether as a fuel for transportation or for varied manufacturing and industrial purposes. The researchers believe studies like theirs could help key energy stakeholders make better-informed decisions. To that end, they have integrated their analysis into SESAME, a lifecycle and techno-economic assessment tool for a range of energy systems that was developed by MIT researchers. Users can leverage this sophisticated modeling environment to compare costs of energy storage and emissions from different technologies, for instance, or to determine whether it is cost-efficient to replace a natural gas-powered plant with one powered by hydrogen. Resources • Drake D. Hernandez, Emre Gençer (2021) “Techno-economic analysis of balancing California’s power system on a seasonal basis: Hydrogen vs. lithium-ion batteries,” Applied Energy, Volume 300 doi: 10.1016/j.apenergy.2021.117314 ### Comments The critical variables here for hydrogen are the price of renewables, the price of natural gas, the price of electrolysers and the disparity in seasonal demand. For areas other than California, such as Northern Europe, seasonal variability and the amount of energy required to cover it will be much larger, so the costs would be higher, increasing the differential to batteries. The price of natural gas OTOH is considerably higher, so reducing the premium, balanced against higher renewable prices, for instance in the case of the UK the premium of off shore wind over Californian solar. I can't access the paper so can't comment on the exact figures they use, but at: https://www.energy-transitions.org/wp-content/uploads/2021/04/ETC-Global-Hydrogen-Report.pdf We find on page 27: ' • Electrolyser costs, which in Exhibit 1.10 are assumed to be around$850/kW51, can be dramatically reduced as the industry achieves economy of scale and learning curve effects. Electrolyser costs of $300/kW are already available in China52, and reasonable estimates suggest that electrolysers could be widely available for$200/kW by 2030 and $100/kW by 2050.53' A fall to$300KW means that (pg54):

' In the past, high electrolyser costs have made it important to run electrolysers at high capacity in order to reduce capital costs per unit of production, which implied reliance on more expensive electricity from the grid. But as electrolysers capital
costs fall drastically, high utilisation will no longer be crucial. As Exhibit 2.3 shows, once electrolyser costs fall below $300/kW, electricity cost becomes the almost sole driver of green production costs as long as utilisation rates are above around 2000 hours per annum. ' Batteries self discharge, at what rate depends on the type, so for instance the recently heavily promoted iron air batteries which are far cheaper than lithium are rated for days storage, not months, whilst once the hit of conversion to hydrogen is taken it can be stored indefinitely. It is far lower cost to store hydrogen in salt caverns, depleted NG wells etc so the availability of such resources determines a lot of the cost with Europe and NA well placed and China in a poor position. (pg43) Storage as ammonia etc is also possible. Some types of electrolyser don't ramp well, and so would be combined with batteries (pg 29) - alkaline and SOFC Although my link does not mention them as they are an immature technology, high temperature PEM is likely to have much higher efficiencies than quoted for PEM which are well suited to coping with intermittency. Views which seek to discount anything other than battery storage make no sense to me at all. Both battery and chemical storage will be needed, melding their different characteristics. It is in my view plain from the above discussion that for areas with wide seasonal variation and consequently the need for high volume storage, notably Northern Europe, not only is hydrogen storage a lot cheaper and more practical, but that advantage is going to increase dramatically with fast falling costs from those given. For areas with very low seasonal variability including much of the developing world which is situated at low latitudes then battery storage might cover much of what they need. Areas such as the North-East US with harsh winters, but OTOH a high summer load peak from air conditioning and readily available resources in both solar and off shore wind are interesting intermediate cases. It seems to me that the best mix needs to be determined case by case in a normal engineering manner, not by rather obsessional edicts about ' the best storage option' It depends on how much and for how long, and what local resources for both generation and storage are available. I'll just add that I have not got access to the assumed price of green or blue hydrogen they are using, or the electrolyser costs or efficiencies. Putting such data behind a paywall is a very unfortunate modern tendency, and greatly detracts from both the usefulness and credibility of reports. However, pulling data from my links they might be using something like$875KW for electrolysers, which should fall to well under $300KW by 2030 For hydrogen prices this link: https://www.sgh2energy.com/economics Shows blue hydrogen at$7kg and green at $10-15kg in California at the moment. If they have used those, it is pretty daft as that is low volume delivered to car filling stations. However they are both pretty pricey at the moment, and my link shows costs likely to fall to under$2kg by 2030 for green hydrogen.

So it is safe to conclude in spite of inadequate data provided by the authors that cost falls by 2030 will be very substantial indeed.

It is interesting that they are recommending hydrogen fired gas turbine peaking plants but it make make sense as the peaking plants already exist and you can probably make them run on hydrogen by changing the burners The new larger combined cycle (Rankine or steam bottoming cycle) plants have a thermal efficiency as high as 62%. I would believe that this is lower cost than batteries although the batteries are more efficient. However, if you have the space with hills and water, pumped storage is more efficient and probably can quickly follow the power requirements. I still think that the best solution is nuclear power for most of the base load and then make hydrogen using the nuclear power and high temperature electrolysis when there is excess electric power available.

operates with blue hydrogen
Sequester power plants to really reduce CO2 emissions

@sd:

I'm a fan of nuclear, always have been, and would like to see a build of 4th gen SMRs close in to urban areas, so that lower grade heat can be piped as district heating for a total electrical plus thermal efficiency of 80% +, as well as hydrogen production in off peak.

But in Europe and the US, we will all have fried from GW long before we have a mass build of nuclear, particularly since we have to work to fantastical radiation safety regs, and they fool around with what they want all the time so that the economics become ridiculous.

We can build out renewables right now, and the economics are good, and intermittency is copable with via hydrogen storage, so in spite of being a fan of nuclear I hope they press on in the meantime.

If nuclear becomes a realistic build option in the West, then it will help a lot.

The IPCC etc are looking to 'all of the above' including nuclear and sequestration to keep heating within bounds.

Here is an article on converting NG power plants to partial and full use of hydrogen in the US:

Maybe the best thing to do would be to just use gas when the renewables are off, and spend the money putting renewables into places that can easily take them (and don't have them yet).
It is a global problem, not a local one.
Getting to 30% with wind is straightforward in many places, way easier than going from 50 to 80% in a rich country, so do the easy stuff first and then, when you have closed the last coal burning plant, start to worry about how to store excess renewables and reuse it.

@mahonj

If we are to have a chance of keeping GW to 1.5C we need to have the technologies ready to roll out at massive scale in the 2030's.

To do that they need early stage roll outs and to start getting some scale.

For instance until recently there was around 0.1GW of electrolysis in Europe.
The hope is to get that to 40GW by 2030, and something like 28GW of that is in the plans of companies currently.

That sounds like a lot, but it is nothing to what will be needed in the 30's and 40's.

We need the early stage stuff to get the volume to really reduce costs.

Delaying moving the German or UK grid percentage of hydrogen will not in reality lead to the closure of a single additional coal plant in India or China, the funds are entirely separate

But developing power to gas in Europe can then be generally applied around the world.

Nuclear power can be classified in two categories: fission and fusion. When bombarding a heavy nucleus (e. g. U 238) with neutrons, it becomes unstable and transitions to two nuclei of equal size and magnitude. A great amount of energy is released in this process. This energy is used to heat water to form steam; the steam is used to drive a steam turbine which in turn drives an electric generator. Radioactivity and radioactive wastes are a result of this fission process. It is not inherently safe and the resulting waste has a long lifetime as a dangerous burden for future generations.
Presently, there are three different types of fusion reactors. These are: Tokamak, Stellerator and HB11. My personal opinion is that the Tokamak has no future and serves solely as an instrument for research purposes. The Stellerator is the far younger type of the first two mentioned and has far more promise of success than the Tokamak.
The HB11 is the youngest to complete this trio and has the best perspectives of all three. The first lab results exceed everything that has ever resulted from research invested in the Tokamak and Stellerator. The fusion processes of the first two described reactors is not free of radioactive wastes but the lifetime thereof is rather limited when compared to the fission process. Nuclear power? Yes, certainly; but only fusion and not fission. HB11has no radioactive wastes whatsoever. For anyone interested, I'd recommend to "google" for HB11 fusion reactor.

With functioning HB11 fusion reactors there is absolutely no need for H2 or an H2-infrastructure.

Fast reactors work now

@yoatmon,

I hate to have to break it to you but we have not yet had a demonstration of sustainable fusion power in laboratory conditions. Even if that was to happen in say the next 5 years or even this year, it will probably take more than 10 years to get the required permits, etc. make the engineering designs and and do the necessary manufacturing to build a single demonstration power plant. I think that it is worth continuing research in this field but it certainly not a short term answer. Under best conditions, we are more than 15 years away from even a single plant producing power for the grid. Just look how long it took to get wind turbines which are a comparatively simple technology to a point where they were an economically feasible source of power.

NuScale has all of the regulatory permits in place for their first Gen 4 Small Modular Reactor facility and has manufacturing expertise and capability in place and they still will not have an operating reactor until 2029. I believe that we will have functioning traveling wave fission reactors in operation long before we have fusion reactors. The traveling wave reactors will burn existing nuclear waste, depleted uranium, natural uranium, etc close to completion. End of nuclear waste problem. Also, we already have enough depleted uranium stored for at least 600 years of power production without any other power sources.

Burning Hydrogen in Gas Turbines for backing up wind and solar makes a lot of sense if it is cost competitive. It is not difficult to convert existing NG power plants to H2 (read: https://www.ge.com/gas-power/future-of-energy/hydrogen-fueled-gas-turbines).
However, you don't need to use renewable electricity to generate hydrogen. A better approach would be to use Municipal Solid Waste (MSW). Two companies are already working on this approach (Ways2H and Raven SR). Most MSW is put in landfills (over 50% in the US) and this generates the worst GHG methane. Converting this to H2 solves this problem and if you capture the CO2 the process is "Carbon Negative".

Use natural gas and hydrogen in combined cycle sequester the carbon

That's right MSW alone will not handle the demand. Norway and Sweden had to import garbage to meet demand (https://www.wired.com/story/will-the-hydrogen-revolution-start-in-a-garbage-dump/) and they burn 53% of their MSW compared to 12% in the US. CO2 capture and reuse like Net Power net-zero natural gas-powered electricity plant in Canada would allow reuse in cement and enhanced oil recovery

enhanced oil recovery
90% of the CO2 stays in the well

@gryf

Raven SR uses a steam/CO2 reformation process to generate hydrogen from municipal waste. When I read about this, I wondered if you could use high temperature pyrolysis and generate hydrogen and solid carbon. Maybe this is not that different from making charcoal except that the charcoal would be the waste product that needs to be sequestered.

$2400/MWh ! LOL. The LCOE for solar is around$35/MWh, for wind \$25-50/MWh.
Just build more wind and solar.

@yoatman:

When and if at some stage in the distant future that we have economic fusion working to solve a problem which Gen 4 fission has already cracked, and assuming that it is so cheap that it takes over all generation, then it will be used to produce bucket loads of hydrogen.

Why? Because otherwise at low demand periods the output would be wasted, instead of earning money producing zero GHG hydrogen.

You crusade to eliminate the use of hydrogen should be broadened to eliminate the influence of gravity.

Here in the UK we already have waste plastics to hydrogen plants, which is somewhat better than dumping it in the ocean.

Biohydrogen from municipal waste is a fine resource, and although the hundreds of millions of people in Europe turn out the resource in copious quantities, there is still power to gas needed to provide anything remotely like an energy balance.

The answer to what we need to effectively decarbonise is 'all of the above'.

@ sd:
"I hate to have to break it to you" but the experimental Stellerator W7X in Greifswald, Germany is presently being scaled up to demonstrate continuous fusion in the late fall of this year. Having reached 3 min. in 2019, the reactor is being updated to achieve the final proof of concept with a record time of at least 30 min.

@yoatmon,

As, I said before, we have not yet had a demonstration of sustainable fusion power in laboratory conditions. Even if they succeed in getting 30 minutes of sustained plasma discharge this year and I hope that they do, this is not a demonstration of power production. The physics, engineering, and manufacturing complications of these devices make fission reactors look like child's play.

assuming that the Stellerator experiments work and can be scaled for future power production and the economics of such power production work out, we are still probably at least 15-20 years from providing power to the grid.

@sd,
Raven SR is a 30 year old H2 production process no one probably remembers.
Developed by Dr. Terry Galloway, it uses a duplex kiln that has the combined functionality of steam/CO2 reforming, heat transfer, solids removal, filtration, and heat recovery.
The syngas process has 55% H2 and 33% CO and could be used in a DMFC like Fuel Cell Energy makes to sequester the CO2 and separate the H2 for other applications like Hyzon wants to do for Class 8 trucks (Raven SR and Hyzon have an agreement).
(References: "Hydrogen from Steam/CO2 Reforming of Waste", Terry R. Galloway, Fred H. Schwartz, and Joe Waidl. Intellergy Corphttps://nha.confex.com/nha/2008/techprogram/P3996.HTM and patent US20150122243A1).

mahonj,

I'm sympathetic to your point but I tend to agree with Davemart. Not least because I live in Denmark and mainly work with PtX... :-b

It's not that easy to explain why PtX is so necessary. Why can't just use wind a solar? Just plant more solar!? (most people think domestic electricity and gasoline consumption makes up the majority of energy consumption - which it doesn't)

Well, in Denmark we already have the situation that peak wind production is 120% of annual average electricity consumption and wind+solar is about 140% of consumption. Yet, wind+solar is only about 10% (!) of our total energy consumption (about 50% of electricity consumption).

But existing wind developers have no motivation to establish more capacity because more wind will only drive down the price of wind power for *the entire fleet*. The have said quite openly that they need more peak electricity demand - i.e. electrolysis - to warrant more wind capacity.

But it just so happens that two one-gigaWatt electrolysis projects have been announced within the last 6 months, so now the tables are turning and we may end up with insufficient RE because project duration of offshore wind is longer than establishing an electrolysis plant (supposedly).

I imagine a future where 70% of 'consumption capacity' is electrolysis and the rest is classical electricity consumption - half of which goes to batteries for transport. In such a scenario, classical electricity consumption will be just 10-20% of total and the times where thermal backup is in use will be minimal. In such a scenario, I would agree that using natural gas to generate <5% of annual electricity demand using natural gas would be OK. I always say: "The first 95% CO2 emissions reduction is 19 times more important than the last 5%!"

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