Green hydrogen and solar will be intricately connected, as is evident in early green hydrogen projects. Most of the first green hydrogen plants could give a second export option to existing renewables projects.
In September 2023, French green hydrogen company Lhyfe and renewables developer VSB Énergies Nouvelles signed a 16-year electricity supply
contract. All the electricity from VSB Énergies Nouvelles’ 13.2 MW wind farm in the Morbihan region of Brittany, France, will supply Lhyfe’s new 5 MW hydrogen production site.
The deal is representative of a trend. In this first phase of the market, a decentralized approach offers the best route to commercial viability. Hydrogen production is co-located with consumption, electricity generation is co-located with electrolysis, and costs are cut. Even so, PPAs can be an ideal instrument for the electricity supply.
Legislation strengthens the case for co-location. Electrolyzers are exempt from grid charges in Germany but still face tariffs when purchasing from the grid. France’s Turpe grid tariff offers no electrolyzer exemptions.
Adrien Appéré, head of development at VSB Énergies Nouvelles, told pv magazine that the Lhyfe PPA will be followed by more. “A PPA with a hydrogen producer is an opportunity to [enhance the value of] the energy produced by wind or PV farms,” he said.
Hydrogen will be a driver for renewables in France and further afield, according to analysts.
“We have seen a couple of PPAs of renewables assets for hydrogen production closed in France but the bigger potential is [elsewhere],” said Thekla von Bülow, co-head of advisory at Aurora Energy Research. “We expect new PPAs for hydrogen production to be closed in Germany in the next months.”
Four green hydrogen electricity PPAs have been closed in France and seven in Germany, according to von Bülow’s data. The largest were closed in Germany, at hydrogen facilities in Thierbach and Rostock where production has not yet started.
“PPAs are usually signed well ahead of the operation of the electrolyzer,” said von Bülow. “As per our knowledge, there are currently no hydrogen projects producing green hydrogen utilizing PPA-contracted electricity. The first PPAs are expected to start delivery by the end of 2023.”
Winds of change
Things are moving fast. In terms of expected operational capacity in 2030, Aurora said Germany leads, with 14.5 GW, followed by the Netherlands
(11.6 GW), the United Kingdom (8.4 GW), and Spain (5.8 GW). France’s expected electrolyzer capacity is 2 GW.
“Germany will require quite complex PPAs,” added von Bülow. The high average carbon intensity of German grid power will drive new renewables capacity and changes in electricity trading conditions could fuel hydrogen growth. “Should Germany split up its market zone, the north of Germany will likely achieve a 90% RES [renewable energy source] share, which would allow electrolyzers in the north of Germany to run on grid power.”
The renewables mix powering green hydrogen could change, too. Wind led hydrogen production PPAs in the fall of 2023 but solar could become more attractive as decades-old deals expire. VSB’s Appéré said the first wind feed-in-tariffs were signed between 2002 and 2005, for 15 years. For solar, contracts were longer.
“For the PV assets, we have simultaneously signed the first feed-in-tariff for 20 years,” he said. “So, since 2017, the first projects free of tariff are the wind farms. In a few months and years, you will see more and more PV projects assigned for PPAs as they do not, any more, receive feed-in-tariffs.”
Those PV assets can have a second life through hydrogen PPAs. Industry insiders say switching from wind to a mix of renewables would reduce risk. Hydrogen economics improve with a lower cost of electricity and higher utilization. A mix of renewables enables this. Hydropower from large reservoirs is the closest to a cost-competitive, 24/7 baseload power, renewable energy source, said Simon Kornek, vice president (VP) for south European origination at Norway’s Statkraft.
What is green hydrogen?
In February 2023, in line with the European Union’s Renewable Energy Directive, the European Commission adopted regulations defining renewable hydrogen rules and clarifying “additionality” criteria for renewable electricity. Green hydrogen producers must ensure the electricity they use is matched by the production of renewable energy. This “additionality” rule mandates the renewable power for green hydrogen production must not come from a renewable asset that started operation more than 36 months before the electrolyzer was operational. Hydrogen plants that begin operation before Jan. 1, 2028 are exempt from this rule, until Jan. 1, 2038. “Temporal correlation:” Until Dec. 31, 2029, hydrogen must be produced in the same calendar month as its renewable energy supply, to be considered green. That will change on Jan. 1, 2030, when hydrogen will have to be produced during the same one-hour period as the renewable energy. Hydrogen producers must ensure that energy suppliers are near their plants. The “geographical correlation” rule relates to bidding zones: regions in which the same electricity price is applied. Exemptions apply, including that if grid-power emission intensity is lower than 64.8 g of CO2 equivalent per kilowatt-hour, the additionality requirement does not apply. Also, if renewables provide, on average, more than 90% of grid electricity, additionality and temporal correlation rules do not apply.
“In Scandinavia, where power markets are already largely carbon-free, hydrogen projects can tap into existing hydropower,” said Kornek.
Statkraft has signed four PPAs for hydrogen production, none of which are co-located. PPAs include supplying renewable electricity to Fortescue Future Industries’ (FFI's) 300 MW Holmaneset green hydrogen and ammonia project in Norway, a green steel project in Sweden, and a 20 MW green hydrogen plant in Germany.
Statkraft is owned by the Norwegian state and Kornek argued that the best way forward is to tap into the larger portfolios of market integrators such as utilities. He said creditworthy integrators for PPAs offer project sponsors cheaper finance via non-recourse funding for which only project cashflow is used as security.
There is more to green hydrogen growth than PPAs. Jack Eastwood, director and corporate operations officer at British green hydrogen company Protium Green Solutions, said the market will also depend on pipelines connecting Europe to North Africa. The infrastructure could be ready by the next decade but Eastwood said he expects mass hydrogen production in Africa to start in the 2040s.
Pipelines can drive hydrogen growth in Africa and Europe. Many unviable European projects could take off as a result.
“We see companies looking to deploy electrolyzers at their renewables sites to mitigate the loss from [electricity] curtailment,” said Eastwood. “It is, now, difficult because hydrogen consumption is not necessarily close to hydrogen production. Over time it will become more attractive because you’ll be able to inject it in the grid, in the long term, or sell it to hydrogen consumers.”
The next steps for PPAs divide opinion. Eastwood said the market is very demand driven, meaning hydrogen producers have to adapt to buyer needs, leading to baseload-type PPAs with obligations on generators.
“Pay-as-produced [-structured PPAs] is an interesting space, because proton exchange membrane (PEM) electrolysis, by its nature, is able to match the production curves of solar and shift that energy supply to later,” added Eastwood. “We will definitely see more pay-as-produced, more large-scale hydrogen, rather than baseload PPAs. It will not need to match demand and supply. I can, for instance, store it.”
As grid injection and large-scale energy storage become feasible, Eastwood expects hydrogen suppliers will have more flexibility. “Therefore, ability to take power as produced becomes easier over time,” he said.
Kornek did not necessarily agree. “We see quite some challenges for hydrogen projects to deal with pay-as-produced solar or onshore wind PPAs,” he said. “Projects will either have to oversize the electrolyzer to absorb all the energy or they will have to deal with significant excess volumes that have to be sold back to the market at an unknown, and probably very low price.”
The Statkraft VP said several business models could coexist. Big, energy-intensive processes will need stable hydrogen supply, meaning reliable power or significant storage. Other projects could require lower utilization rates and produce hydrogen when electricity prices are low.
Kornek and Eastwood agree storage and transportation will be the major drivers of change, ultimately leading to a commoditized market. Industry insiders expect a flexible market in the next 15 to 20 years.
In this decade, Eastwood expects the first hydrogen projects to become operational. The first large-scale electrolyzer projects should go live toward the end of the 2020s, he predicted. “Over the 2030s, we’ll start to see these ‘backbones’ developing into hydrogen regions with networks of piping which, in turn, will start to connect to one another,” he said.
There’s more to hydrogen evolution than market mechanisms. The European Union’s latest Renewable Energy Directive split opinion among respondents approached by pv magazine. Aurora Energy Research said there was a lot more clarity in the regulation but Kornek argued European Union regulations are holding back investment. He said the first indication of how new rules would impact the sector should emerge over the next 12 to 24 months.
“The delegated act, as currently written, makes it very complicated to realize the green hydrogen targets in Europe,” said Kornek. “In particular, the strict requirements on additionality, temporality, and geographical correlation will be extremely difficult to comply with and will make green hydrogen more expensive than necessary.”
New European Union rules on green hydrogen could also affect the viability of different kinds of PPA. Protium’s Eastwood said that an obligation to correlate energy generation and hydrogen production on an hourly basis, which would come into effect in the 2030s, would reduce the value of pay-as-produced PPAs while at the same time, consumption on demand would come at a premium.
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