J’ai publié un article sous ce titre dans la Oxford Review of Economic Policy, Volume 35, Issue 2, Summer 2019, The Age of Electricity, dont je ne peux partager le lien sur les médias sociaux, mais que je suis autorisé à mettre sur mon blog. En bref, ça dit ceci: Achieving net zero greenhouse gas emissions is very challenging. Given the limitations in the direct use of renewable energy for heat and mobility, electrification of the broad economy seems a must, provided electricity supply is CO2-free. The recent cost reductions of solar and wind technologies, their immense potential, and the improvement in electric technologies for industry and transport, open new avenues for achieving humankind’s climate mitigation goals. However, a large fraction of the best solar and wind resources are situated far away from large consumption centres. Moreover, the variability of solar and wind and the shortcomings of electricity storage limit the scope for direct electrification. Indirect electrification through electrolysis of water and the use of hydrogen and hydrogen-rich feedstock and fuels may in all end-use sectors complement electrification where it appears excessively challenging, serve the power sector itself, and also help harness remote resources and ship them to consumers or industries.
Fossil fuels currently play a critical role in industry, not only as sources of energy, but also of feedstocks and process agents. Clean electricity could provide a sustainable alternative, but hurdles remain – particularly in terms of costs.
In Northern Europe, offshore wind is showing potential to provide significant amounts of clean power to industry, with generation costs possibly falling to the range of €55 to € 70/MWh.
This increasingly affordable renewable electricity strengthens the potential for cost-effective replacement of fossil fuels by electricity in industry. However, the continuing cost gap with the direct use of gas or coal to generate heat limits this potential to those electric technologies that are at least twice as efficient as fossil fuel uses. For now, a complete shift would require carbon prices at levels up to € 150 per tonne, a level even higher than projected for 2040 in the World Energy Outlook Sustainable Development Scenario (SDS).
Another realistic first step towards accelerating sustainable energy in industry involves hydrogen produced from clean power via electrolysis from water, directly substituting for hydrogen produced from fossil fuels. Continuer la lecture
Reducing long-term greenhouse gas (GHG) emissions in the industry sector is one of the toughest challenges of the energy transition. Combustion and process emissions from cement manufacturing, iron- and steelmaking, and chemical production are particularly problematic.
But there are a variety of current and future options to increase the uptake of renewables as one possible way to reduce industry sector energy and process carbon dioxide (CO2) emissions, which we examine in detail in a new IEA Insight Paper, Renewable Energy for Industry.
The main finding is that the recent rapid cost reductions in solar photovoltaics (PV) and wind power may enable new options for greening the industry, either directly from electricity or through the production of hydrogen (H)-rich chemicals and fuels. Simultaneously, electrification offers new flexibility options to better integrate large shares of variable renewables into grids.
Responding to popular demand, I publish a revised graph showing the cost of hydrogen from electrolysis of water for different load factors, but based on the most recent information about the cost of alkaline electrolysers in large plants, as provided recently by NEL: USD 450/kWh as already mentioned (Note: this graph was again revised on 3 May).
Here you can see three zones: the zone of “free” surplus from solar and wind in Europe (but that would likely apply to Japan as well, and other countries with good but not very good Wind and solar resources); electricity is considered free but the occurrence are relatively unfrequent and I considered 500 to 1500 full load (equivalent) hours a year for the electrolysers; variable renewables in Europe, where solar and Wind combined are unlikely to exceed a capacity factor of about 50%, and the same in most favoured régions of the world.
This leads me to somewhat attenuate my previous prevention against the concept of manufacturing hydrogen from “surplus” variable renewables in countries with average resources. The cost may be found acceptable for some usages, in particular where procurement of other sources of clean hydrogen is not easy. However, it is unclear if some other ways of using this surplus electricity, including as a source of heat, would not prove economically preferable.
In any case the quantity issue remains: these surpluses will not likely suffice for all current and future, industrial and energetic, uses we have for hydrogen in a climate-friendly energy world. We will need more, much more, and I doubt all could be produced in these regions. Beyond “free” surpluses we would need to deploy many more wind farms and solar farms in addition to those that will be needed to provide the bulk of our grid electricit. And for what? For generating hydrogen at twice its cost in those sunnier and windier areas that have a low population density and very low local electricity demand.
Hydrogen is not easy to transport, and costly to store as a gas, so for most of its usages we would likely bound it to some other atoms to form a variety of energy carriers or fuels, with carbon atoms (methane, methanol, MCH, DME, alcools and hydrocarbons) or without, such as ammonia. And then, transport on land via pipelines, on seas with ships, would be relatively straightforward and represent a small increase in overall cost. Hence importing from best-resource low-demand areas would likely be a very valuable option for complementing local renewable resources in average-resource high-demand areas.
In any case, the economic case for clean hydrogen production vs. fossil fuel based hydrogen manufacturing looks better than previously thought. Except maybe in very cheap natural gas countries, renewable-based ammonia generation and possibly other commodities, including energy carriers, could prove a competitive option from now on, even with no carbon cost or consideration of capture and storage of carbon dioxide.
More on this topic: read my 6-page note on the IEA website, where I explain in particular how a large-scale all-electric ammonia plant could work on variable renewables such as a combination of solar and Wind.
As noted in my latest blog note, hydrogen production from electrolysis of water, based on hydropower, was the dominant technology until the 60s before natural gas reforming became the new normal – with huge greenhouse gas emissions. And I noted that the new, very recent competitiveness of solar and wind could, and in fact should, open a new era for clean hydrogen production. I did not expect this was already planned, according to Nel. This Norwegian company recently designed, for an untold client of the fertilizers industry, in an unnamed country, the largest-ever electrolyser plant, which will run on solar power or wind power or both, most likely without any connection to the grid. Hydrogen would directly feed an industrial plant next to it – I guess ammonia but perhaps not limited to it. Interestingly enough, the scaling-up lead to significant cost reductions, at USD 450/kW. In the analysis I had published, I conservatively chose USD 850/kW based on the IEA Technology Roadmap on Hydrogen. If this project actually sees light, this will look like a dream coming true, earlier than hoped.
Il faut saluer l’annonce faite à Davos d’un “Conseil de l’hydrogène” qui regroupe les CEO de 13 grandes compagnies: Air Liquide, Alstom, Anglo American, BMW GROUP, Daimler, ENGIE, Honda, Hyundai Motor, Kawasaki, Royal Dutch Shell, The Linde Group, Total and Toyota. Mais cela n’interdit pas de jeter un regard critique sur le rapport publié à cette occasion, “Comment l’hydrogène facilite la transition énergétique“.
Combien de fois n’avons-nous pas entendu cela? “Pour chaque MW d’éolien ou de PV installé, il faut construire un MW de centrale thermique pour compenser l’intermittence des renouvelables”. Je vais essayer d’expliquer pourquoi c’est faux et comment calculer le “back-up” éventuellement nécessaire.
GDF Suez – mais oui! – vient de remporter un appel d’offres en Egypte pour la fourniture d’un parc éolien de 250 MW avec le plus bas prix jamais vu pour l’éolien (hors subvention de type “production tax credit” comme aux Etats-Unis) : 41 dollars le mégawattheure, autrement dit, moins de 4 centimes d’euro par kilowattheure. Il est vrai que la ressource éolienne en Egypte est exceptionnelle, et que le projet se trouve dans le golfe de Suez, où GDF Suez se doit d’être à son aise…
Les compétiteurs ont tous proposé des prix inférieurs à 50 dollars.
Quelques mois après le record solaire de Dubai, à 58,4 dollars le MWh, l’éolien démontre que c’est toujours lui qui tient la corde pour les plus bas prix.
I’ve been saying this many times: the competition is not between solar thermal electricity (STE, or CSP: concentrating solar power) and photovoltaics (PV), but between STE and PV+storage, mostly PV+pumped storage plants (PSP, or PSH: pumped storage hydropower). But I was not expecting to witness this in North Chile – one of the dryest places on earth, one of the best for CSP but not really good for hydropower. This was without taking account of the possibility of Okinawa-style, seawater PSP. The Espejo de Tarapacá project developed by Valhalla Energy, associating a large seawater PSP of 300 MW with 600 MW of PV plants, would represent a significant challenge for STE. It remains to be seen, however, how the economics work, and in particular if the lowest cost of PV makes a difference large enough to compensate for the losses in PSP, significantly greater than in thermal storage. But this might well be the case.
I talked on Friday 19 with Francisco Torrealba, promotor of this project. He said the cost of the PSP is USD 1300/kW because it needs minimal civil works for the upper reservoir, only tunnels and power chamber (about 13% of the overall costs). It benefits from an important head of 600m.
Its expected round-trip efficiency would be 78%. The storage capacity is about 80 000 GWh, 260 hours at full power.
A power purchase agreement (ppa) at USD 100/MWh would provide 90% of the revenues of the project, while another 10% would come from capacity payments. The ppa will be made with the PSP part of the project, delivering 200 MW 24/24, 7/7. PV power will produced at USD 70/MWh and sold (?) on the spot market (so there might be two financial entities, one PV selling, one PSP buying from the spot and selling to the mines). The cost of storing one kWh would be about USD 50/MWh but only 2/3 of the electric output would need to be stored so on average the additional cost to the PV would be about USD 30/KWh.
Valhalla energia is currently finalising the environmental impact assessment and hopes to sign a ppa with a big mining company on the SING (sistema interconectado norte grande) in early 2015, then to get environmental approval by July.