The commercialisation of hydrogen projects is coming thick and fast. The growing availability of opex subsidies and capital grants, investor willingness, and corporate investment into partnerships and technologies are among the factors driving hydrogen towards commercial viability. But a number of barriers to development of the hydrogen economy still exist. Earlier in this series, we discussed how to access funding and how to create an offtake strategy.
Commercial-scale projects are the next step for a hydrogen economy, but this stage involves greater complexity and demand for resources. However, in many parts of the energy sector—particularly in developed markets—there is an established framework or, at the very least, established options for structuring commercial-scale projects. In this article, we examine how these principles can be applied and adapted to clean hydrogen.
Structuring and implementing a green hydrogen project
First and foremost, a reliable supply of electricity and water will need to be secured to produce green hydrogen from electrolysers.
Since the hydrogen is only ‘green’ if the power comes from a renewable source, offtakers will expect the provenance of the input power to be verifiable.
A number of options then exist for power to be supplied to the electrolysis plant. One approach would be for a dedicated renewable energy source to be located on, or near to, the same site as the electrolysis plant as part of an integrated project, where a special purpose vehicle owns both the power generation assets and the electrolysis plant.
This ‘GreenCo’ would therefore not need to buy power from a third-party source, but could enter into a power-purchase agreement (PPA) with a third-party offtaker, either as its primary source of revenue, only using electricity to produce hydrogen through electrolysis during periods of excess generation, or as a secondary source of revenue to sell the surplus power generated that is not required by the electrolysis plant.
There is also the option that the power generation and electrolysis projects are not integrated, which is perhaps more likely. There could then be a number of ways in which the GreenCo could be supplied with renewable power. Most obviously, electricity generated from a renewable source could be sold to the GreenCo to be used at the electrolysis plant under a private wire PPA—where there is a direct and dedicated physical connection between the electricity source and the electrolysis plant.
Alternatively, the electrolysis plant could be connected to the grid and the GreenCo could buy its power under a corporate PPA—where the generator does not supply the electrolysis plant directly. The corporate PPA might hedge its wholesale energy costs and, most importantly, ensure there is a contractual link to an identifiable renewable energy source to verify the green credentials of the hydrogen.
One final option would be for the GreenCo to offer a tolling service to a third-party renewable power generator. This structure would mean power is converted into green hydrogen, which the renewable power generator would then be able to sell for its own account. An advantage of this approach is that it may enable renewable energy projects currently curtailing their power generation to monetise the energy that is excess generation capacity.
Unless a tolling structure is used, the GreenCo will need to sell the hydrogen it produces under one or more hydrogen sales agreements to secure the revenues for the project, although—as noted above—it is possible that an integrated project may also obtain at least some revenues by selling power.
Regardless of which option is selected, there are a number of other key considerations. For instance, the GreenCo will need to secure a sufficient and reliable supply of water to the electrolysis plant. Up to 10t of purified water is required for every 1t of hydrogen produced by electrolysis due to the fact that oxygen has an atomic mass 16 times that of hydrogen.
It is also important to acknowledge that purification of seawater through reverse osmosis adds to capex and operating costs and requires significant energy input. This means economical water supplies for electrolysis are, at least for smaller-scale projects, most likely to be derived from relatively pure and unpolluted freshwater supplies, although these may still need to be processed and filtered. However, at larger implementation scales, published studies have suggested that offshore wind-powered electrolysis plants incorporating reverse osmosis should not appreciably increase the cost per kg of green hydrogen.
The possibility of methanation should also be investigated, since it provides a way to get green hydrogen into natural gas storage and distribution systems without being affected by any limits on the direct blending of hydrogen. If a project produces hydrogen surplus to its offtakers’ demand, adding an integrated methanation plant, or supplying excess hydrogen to a separate methanation operator, could allow that surplus to be exploited.
Regardless of the jurisdiction, any clean hydrogen project structure will necessarily need to take account of developing regulatory frameworks for clean hydrogen and available government support.
Structuring and implementing a blue hydrogen project
Unlike green hydrogen, blue hydrogen projects require the supply of natural gas as a feedstock, as well as access to a suitable carbon sink to store captured CO₂. This allows for a comparison to be drawn with the structuring of LNG liquefaction projects. However, one key difference is that LNG liquefaction projects are often conceived from the outset of an upstream gas development project, which is unlikely to be the case for a blue hydrogen project. If the upstream project from which gas will be supplied to the blue hydrogen project is already producing gas, or if the gas is not from a specified source, then lenders will have a lower exposure to ‘project-on-project’ risk.
Instead, the most likely way that blue hydrogen projects will be developed is by common CO₂ transport and storage networks or hubs acting as the enabling infrastructure for clusters of a range of capture projects that include gas power plants, industrial production, bioenergy, and direct air capture, in addition to blue hydrogen production.
In this scenario, the steam methane reforming plant incorporating CO₂ capture, such as an amine-based technology, would be held in a single special purpose vehicle (BlueCo) separately from the transport and storage networks. The transport and storage networks would include CO₂ compression units to convert the CO₂ gas into a liquid, pipelines to the underground storage site and CO₂ injection facilities at the storage site. Adding post-combustion CO₂ capture technology to what is otherwise grey hydrogen production could capture around 95pc of CO₂ that would otherwise be emitted, although it may also increase the cost of the hydrogen produced by as much as 35pc.
A major factor in establishing the technical and economic viability of a blue hydrogen production project is the availability of, and access to, a suitable storage facility to sequester captured CO₂. Economic savings and reduced risk could be achieved if the steam methane reforming process can be performed close to a CO₂ storage facility—an advantage of the cluster or ‘hub’ approach.
It is still in its early stages, but one new technical area could involve injecting CO₂ into natural gas reservoirs to displace and enhance the recovery of natural gas, which is 2.75 times denser. This approach—pioneered by Saudi Aramco—could be used to sequester CO₂ produced by steam methane reforming, or it could be injected into a nearby spent oil or gas well.
A merchant structure could also be utilised, where the BlueCo could buy gas under a gas sales agreement, produce blue hydrogen, and sell it to one or more hydrogen buyers under a hydrogen sales agreement.
Another option would be to establish a tolling structure whereby the BlueCo uses its facilities to provide a tolling service to the gas owner, converting natural gas to blue hydrogen in accordance with the gas owner’s nominations and against the payment of a tolling fee. The gas owner (toller) could then sell the resulting blue hydrogen for its own account.
The main advantage to a tolling structure for the BlueCo is that it is not exposed to price risk in either the gas purchasing or the blue hydrogen sales. Consequently, there is also a substantial reduction in risk for project finance lenders to the BlueCo—assuming a long-term agreement is in place with a creditworthy gas owner.
Similarly, structuring projects on a tolling basis could facilitate financing, given the nascent stage of the blue hydrogen market. This structure generally concentrates profits, as well as market risk, away from the BlueCo, which may have adverse tax consequences. It also requires willingness of the gas owners to accept market risk in gas and blue hydrogen pricing and will depend also on available government incentives.
Getting commercial-scale hydrogen projects off the ground
Once a structuring option has been selected, contractual agreements will need to be reached. The GreenCo or BlueCo will need to enter into a construction contract, or may even need to sign construction contracts for different elements of the integrated project. Additionally, an operation and maintenance agreement will be needed, as well as financing. Project sponsors will also either enter into a joint venture or a shareholders’ agreement.
Indeed, there are a handful of structuring options available for commercial-scale green and blue hydrogen projects that are tried and tested in the energy sector and can be utilised to make the market. While the hydrogen economy is still in its infancy, the pieces are now falling into place to unlock the industry’s vast potential.