In the long run, Germany will need seasonal storage of solar power from the summer for the winter. German researchers are banking on “power to gas” (P2G). Craig Morris takes a look at how far away we are.
Pipelines offer storage capacities for excess energy – but the conversion of electricity is not quite there yet. (Photo by Buridans Esel, CC BY-NC-SA 2.0)
Since at least 2011, German researchers have been selling the concept of storing excess renewable electricity, especially in the summer, as a gas in the country’s existing natural gas lines, which could then be used for any purpose natural gas serves. The topic remains hot, with independent utility association VKU calling P2G a “promising” storage option just last month. And this month, Germany’s gas lobby group produced its own study showing that underground gas reservoirs could store some 200 terawatt-hours of “green gas.” And as I showed in my last post, IFEU has P2G on its roadmap by the mid-2030s.
Technically, we could start implementing it today, but it would be costly. Let’s do a quick back-of-the-envelope calculation.
We will first assume that green electricity costs 10 cents per kilowatt-hour. Right now, roughly 5-9 cents is paid for wind power, with new solar arrays currently coming in between 10 and 15 cents. Power from biomass generally costs a bit more, but 10 cents is a nice round ballpark figure.
Essentially, we would use the excess electricity to split water into hydrogen and oxygen, storing the hydrogen as “green gas” in natural gas networks (the oxygen would be emitted as a harmless waste gas). But nearly half of the energy contained in the excess green power could be lost in the process. So our kilowatt-hour of excess green power now costs 20 cents as green gas – and we have not even included any costs for electrolysis facilities.
A liter of gasoline or diesel contains around 10 kilowatt-hours of energy and currently costs around 1.50 euros in Germany, putting the price of a kilowatt-hour from gasoline at around 15 cents – but after taxes. The pre-tax cost is closer to four cents – roughly a fifth of what renewable hydrogen is likely to cost a decade from now.
The situation is not much better if we directly compare green gas to natural gas. I just looked up the best price on a consumer advocacy portal for my neighborhood, and the cheapest (after-tax!) offer was 5.6 cents per kilowatt-hour – between 3 and 4 times less expensive than green gas would be in Germany.
Of course, the cost of PV continues to drop, though the cost of wind power has largely stabilized. Going forward, the price of oil & gas is also expected to go in only one direction: up. Nonetheless, the merger in price between oil & gas and green power is unlikely to come about anytime soon; IFEU’s estimate of the mid-2030s is as plausible as it is speculative.
One other scenario is worth mentioning: conversion of Germany’s power mix on the grid, which includes nuclear and fossil electricity. When prices on the power exchange dip down to just a few cents, the equation is obviously much different – and I recently called for Germans to stop thinking in terms of excess power from renewables and simply think of excess power, including nuclear and fossil power. This scenario is indeed more likely than (green) hydrogen for the interim, so I am mainly arguing that a transition to green hydrogen remains a vision that is a few decades away.
Germany has few other options right now for seasonal storage. At least in economic terms, the country would therefore be well advised to design its energy transition so that the need for seasonal storage is postponed until that price parity approaches.
Craig Morris (@PPchef) is the lead author of German Energy Transition. He directs Petite Planète and writes every workday for Renewables International.
Electrolysers can provide frequency regulation for the grid. They should be able to earn money for providing this service, but I believe this is not the case in Germany at the moment.
Given the large and still increasing amount of PV and wind, there will likely be more periods where electricity spot prices are very low. These glut prices probably aren’t related to the average price of renewables (The 10c/kwh ballpark).
The capital costs for electrolysers are probably very important if they can only run for a fraction of the time.
I am very curious to see a more detailed cost analysis for a range of different spot prices, running time, capital costs, and frequency regulation payments. I think this may look somewhat better than the picture painted by this article.
But agreed, it is definitely going to cost more than sucking gas out of a hole in the ground for the foreseeable future.
Craig
This clearly indicates that Power2Gas is a much cheaper and more efficient alternative than PV + Batterystorage.
H2@ 86.5% and Synthetic Methane @ 80.5% are equivalent in efficiency according to this study using HT electrolysis http://www.edgar-program.com/uploads/fckconnector/af452586-9a1a-478f-90ef-96d757006cde
I have not seen any estimates of the comparative carbon cost of the alternatives either. ( As I recall PV panels only produce a positive carbon footprint after 3 years of continuous use.)
It does look extremely promising for the http://www.northseapowertogas.com/ group, I also found a story there about “Scottish wind farms paid £1 million to shut down one day” such a waste. http://www.northseapowertogas.com/news/619
The calculation has a major flaw. Storage is not done with average price energy, but with cheap excess energy that has no current consumer and had either to be disposed (they run it throgh big resistors) or not produced (e.g. turn off wind farms). Since renewables have no input costs, every price on the spot market is high enough to produce renewable energy. On very windy days electricity can besome as cheap as 2 cents/kWh. And this is the cheap energy that gets stored. Its the simple market mechanism. Storage is done with an energy excess on the supply side, that drives prices down and the low marginal costs of renewables make them still competitive at low prices.
The above is correct if you assume a constant price of renewable electricity.
However, right now there are already time slots where wholesale prices go into negative territory, as you have been reporting at renewablesinternational. Those time slots will increase in frequency as more renewable comes online.
Most of the gas will be generated when demand can’t keep up with the supply of renewable electricity.
Interestingly, generating hydrogen at a minus 2 cents per kWh time slot will give a price of minus 4 cents for the hydrogen under your assumption of 50 percent efficiency. 🙂
You miss the point I believe. The reason for power to gas is storage. You only store electricity as gas when you don’t want it, i.e. there is surplus power from renewables or nuclear. This tends to lead to zero or negative power prices. Yes we need to factor in the electrolysis equipment and we should also factor in the methanation step, converting the hydrogen to renewable methane. Yes, there is an energy vector conversion hit but the whole point here is storage, i.e. conversion of energy from one form to another. Whether we use that renewable methane for heat or power is irrelevant, it is capturing a renewable energy source and using it at a later date without having to replace a very good existing infrastructure called the gas grid. If we don’t capture that energy in this way then we lose 100% of it. The big question is how to make it commercially viable and almost certainly that will be in conjunction with other technologies, not as a standalone.
Actually if electricity is used that would otherwise be spilled, the price would be €0.00/kWh 🙂
That’s obviously not quite fair, but one should keep in mind that this is not a solution for bulk gas production, but for fixing the intermittency issue. Compare it with the price of a kWh generated by the emergency generators of your local hospital: that price is horrendous, but it’s the price of supply security, not electricity as such.
BTW from the studies I have seen, for a mix of around 60% wind and 40% solar, no seasonal storage will be needed in central Europe. This is actually an argument for going for such a mix, which will also exploit the decorrelation on synoptic time scales between wind and solar. The synoptic time scale (weeks to months) will then be the longest that needs to be accomodated by storage.
Hydrogen cannot be used in existing natural gas piping for several reasons, the most serious being hydrogen embrittlement. An entirely new/reworked pipeline system would be required for dual use – methane & hydrogen. All burner tips would need to be one or another, hydrogen or methane.
Hydrogen could be stored for use in reworked, former natural gas power plants. It could not be practically used elsewhere except in a new hydrogen gas pipeline system.
Hydrogen plus carbon dioxide form methanol NOT methane. To form methane, one must mix hydrogen and pure carbon (likely derived from coal).
This invalidates the P2G concept as used here.
[…] say this situation considerably changes the calculation. I would simply clarify what I meant in my previous post when I wrote, “This scenario is indeed more likely than (green) hydrogen for the […]
Craig, i believe you’re missing the point of how the reasoning behind power2gas when you calculate to use regular power prices for the production of hydrogen. The point, as other commentators have mentioned, is to use excess electricity that otherwise would be spilled or curtailed, thus it is free of charge. Feeding the hydrogen in the natural gas pipeline, is, unlike the first commentator posted, very much possible. The idea is not to store pure hydrogen, but mix natural gas and hydrogen, thus increasing the energy content. No upgrades are needed to do so in limited quantities.
From an owner’s perspective, you’d feed the hydrogen back as electricity during peak demand times, ideally maximizing your profit as your input fuel is free and your output receives the highest price possible.
Another aspect you’ve missed is the opportunity for using the hydrogen as fuel for FCEVs. Using hydrogen makes a bunch of sense, but not the way you’ve described it.
Emanuel, thanks for writing. I believe I address your comments in a later post here: http://energytransition.de/2013/07/storing-excess-nuclear-and-fossil-power/. The power that would be curtailed or lost is not free in Germany; feed-in tariffs still apply. And I know of no fuel cell car that I can buy.
[…] Por esta razón me parece muy interesante la noticia de que E.on ha empezado a inyectar a una escala industrial hidrógeno en la red de distribución de gas. Esta tecnología cuenta con un importante apoyo desde el gobierno alemán, aunque hay quien tiene ciertas dudas de que sea una tecnología competitiva. […]
Hello Alan Drake,
Just dropping in to say that hydrogen plus carbon dioxide *can* be made into methane. It’s called the Sabatier Reaction, has been known for a century, and it’s done in practice on industrial pilot scales eg. at the ZSW in Stuttgart. No “pure carbon” required.
Production of methanol from the same reagents is a very similar process. The determination of which products come out of the process is a fine art which owes much to the choice of temperature, pressure, catalysts and ratios of input reagents.
Hydrogen is frequently present in natural gas supply and mixing of pure hydrogen into the methane-dominated gas network up to a small partial pressure (typically equivalent to 2% or 5% by volume) is permitted. Since older natural gas distribution pipes were often originally designed to distribute “town gas” manufactured from coal (ie. a toxic mixture of carbon monoxide, carbon dioxide, hydrogen, methane, sulfur dioxide, etc.) they are very tolerant to hydrogen admixture.
(Are you possibly the same Alan Drake who until recently used to post as AlanFromBigEasy on The Oil Drum? Hello, if so! I was xoddam on that site — never so prolific as you!)
Great article Craig Morris.
I just discover this blog and I plan to follow it.
Thanks to you and the other person who posted a comment here now I have a good idea about the cost.