This is an extract from a recent paper “Financing a world scale hydrogen export project” by Oxford Institute for Energy Studies which examines the financing of an ‘Archetype’ world scale hydrogen export project, where 1 GW solar power is used to make green hydrogen which is converted to 250,000 tpa green ammonia for export with a capital cost in the region of USD 2 billion.
The global green hydrogen market has been forecast by the IEA to grow from almost zero in 2021 to 9-14 mtpa in 2030 and 125-300 mtpa by 2050. The wide range is due to many uncertainties including: (i) end-user demand which will be, at least initially, largely a function of government policy; (ii) competing technologies and the rate at which costs fall, and (iii) certification and decisions over which types of lowcarbon hydrogen will qualify for government support. The IEA also projects exports of 12mtpa of lowcarbon hydrogen by 2030, of which almost 90 per cent is expected to be green hydrogen and the majority transported as green ammonia.
The IEA forecasts that current green hydrogen production costs of USD 3-8/kg will fall to USD 1.3-4.5/kg in 2030 and USD 1.0-3.0/kg by 2050. While some hydrogen projects are competitive at current high fossil fuel prices, at present almost all low-carbon hydrogen projects will require government support to attract investment, especially at the rate required to meet net zero targets by 2050. Substantial capital will be required to develop this new industry. Estimates range from USD 80-300 billion from now until 2030 with very much larger numbers through to 2050. The use of low-cost capital (debt and equity) will play its part in lowering the cost of green hydrogen, and both debt and equity investors have a substantial appetite to invest in the hydrogen sector.
Archetype Hydrogen Export Project
For the purpose of illustration, an archetypal hydrogen export project (the ‘Archetype’ project) will be considered, comprising 1 GW solar power generation, hydrogen electrolysis, and a 250 ktpa ammonia plant with the ammonia exported by ship to a remote single market. The assumed total capital cost is USD 1,875 million.
The total project cost, including financing costs, is assumed to be USD 2,100 million in money of the day. Assuming a debt:equity ratio (DER) of 60-70 per cent, USD 1,250-1,450 million of debt would be required. Servicing debt and equity comprises 75 per cent of the total cash outgoing with operating costs amounting to only 25 per cent. Debt service has been split into principal and interest and the dividends have been allocated between the return of equity capital (with no return) and the return on equity (per cent p.a.) to allow comparison. The variable components, being interest and return on equity, are the components the project should seek to minimize and represent slightly more than the total operating cost.
According to the capital asset pricing model, the cost of capital is a function of the perceived riskiness of a project compared to the average market risk. The risk exposure, and hence cost of capital, of the project company can be minimised by efficient allocation of the various risks among the project parties best placed to manage them to develop a robust, ‘bankable’ risk allocation structure that allows the level of debt to be maximised.
The overall project, from power generation to end user, has an inherent risk profile. The risk profile of the project company can be mitigated for the benefit of its investors by a combination of:
- Government support from both importer and exporter countries
- Allocation of risks among the project parties by the project agreements (including insurance)
- Further allocation of risks between debt and equity and the sponsors effected by the finance agreements.
Project Ownership and Commercial Structure
While a number of models could be considered, this paper considers the following three models:
- Integrated Merchant Model: This is the model under which all the export facilities (solar farms, hydrogen unit, and ammonia plant) are owned by the project company and the green ammonia is sold by the project company, as seller, to the buyer under a Green Ammonia Sales and Purchase Agreement (GASPA). It is anticipated that the buyer will own or lease the import facilities. The shipping capacity, a fleet of ammonia carriers, is expected to be owned by a specialist shipowner.
- Segregated Merchant Model: The Segregated Merchant Model is the same as the Integrated Merchant Model other than that the renewable power generation, solar farms in the case of the Archetype project, are owned by one or more third parties who sell power to the project company under long-term power purchase agreements (PPAs).
- Tolling Model: A new commercial model was developed for LNG projects in the US around 2010, where the party that would traditionally have been the buyer of LNG instead signs a tolling agreement with the project company. The toller then pays a capacity and operating fee to a liquefaction plant for liquefaction services, purchases its own natural gas, sells the LNG produced but retains the optionality not to produce LNG if margins are unfavourable. This model could equally be applied to green ammonia production where the project has the capacity to produce 100 per cent green ammonia but also has the optionality, if grid-connected, to sell power at times of peak price or buy power at times of negative prices and also, potentially, sell hydrogen into its domestic market.
With a UJV, each sponsor raises debt, if it wishes to, independently. Whereas, with a project company, the sponsors must jointly agree on the project company’s financing and have the option to: (i) fund it with a mixture of equity and intercompany loans or guarantees pro rata to their shareholdings (Corporate Finance) or (ii) to require the SPC to raise debt in its own right with only limited and contractually defined support from the sponsors (Project Finance).
With corporate finance, lenders look to the credit of the sponsors, and this offers the benefits of flexibility and speed, as it avoids the relative complexity of project finance, and, if they have strong credit ratings, the benefit of lower debt costs. With project finance, lenders are exposed to the credit of the project and will require more extensive diligence and structuring. Where one sponsor is relatively weaker than others, this approach gives all parties a greater confidence in securing debt for the entire project. It also means that the sponsors may not need to consolidate their share of the project on their balance sheets but only treat it as an equity investment.
The principal sources of debt for a hydrogen export project would be: concessional finance; international and domestic commercial banks; the project bond market; export credit agencies; and multilateral development banks.
Successful green hydrogen/ammonia export projects will have been selected by a buyer on the basis of a formal or informal competitive process as the supplier of reliable low-cost hydrogen. The ability to deliver at a low cost will be a function of: the availability of low-cost, high load factor green power; the cost and efficiency of the hydrogen and ammonia plants; and the cost of capital.
The initial investors in the project are likely to be companies that have the engineering and project management skills along with sizeable balance sheets required to develop a project of the scale and complexity of the Archetype project. They are likely to be major resource companies or global utilities.
Everything else being equal, the cost of equity should fall significantly at each de-risking milestone, the principal milestones being (i) FID when the project would have a contractual framework substantially fixing the capital cost and the offtake price and (ii) completion of the project. There is a substantial pool of investors, typically institutional investors such as infrastructure funds, that has the appetite to invest in low-risk infrastructure assets with lower investment return hurdles than resource companies.
This paper, for illustration, examines an Archetype project, using 1GW of solar generation to produce 250 ktpa green ammonia be sold at a fixed price of USD 770/tonne (just sufficient to meet the assumed cost of capital). This compares with a 5-year average price of a little over USD 600/tonne but over USD 1,300/tonne at the time of writing. Assuming a 20-year offtake contract and a 15-year loan (with a 3- 27 year construction period), the Archetype project can support a DER of around 65 per cent. For early projects and especially if no completion guarantees were available, the DER might be closer to 60 per cent. However, the DERs achieved by projects are expected to increase over time as more experience is gained with the technology and lenders can accept longer term loans.
The debt financing can be optimised to minimise the cost of capital by: (i) maximising the initial DER; (ii) continuing to maximise the DER through the life of the project, and (iii) minimising the interest margin. Of these, the initial DER is very much set by the robustness of the offtake agreement. However, in terms of impact on the cost of capital, maintaining a high DER throughout the project life is even more important. This can be achieved either by seeking to maximise the term of the initial financing or planning to refinance one or more times over the project life (and ensuring the terms of the initial financing will permit this). Minimising the margin is broadly as important as the initial DER and can be done by prioritising concessionary lenders and running a competitive process.
The equity financing can be optimised by refinancing a portion of the sponsors’ initial equity, when the project has been de-risked, perhaps at completion, with lower cost equity from investors with a lower risk/return appetite. The sponsors can then receive a premium, giving them a higher return for the development risk they have assumed and enabling the re-cycling of capital for future projects. The analysis indicates that with the combination of an increased loan term, a higher DER, and the introduction of de-risked investors at completion, the initial investors could bid a 5 per cent lower green ammonia price (significantly increasing their competitiveness) and still achieve a better return on equity than in the Base Case.
The Way Forward
The conclusions apply to financing projects early in the development of the green hydrogen industry and will undoubtedly change in the future as the industry matures:
- Lenders will likely be prepared to accept completion risk where the technology is reasonably established – as can probably be argued for green ammonia – and if there is a robust contracting strategy. Less mature technologies, such as liquid hydrogen, would be expected to demonstrate a successful track record of construction and operation before lenders would accept pre-completion exposure.
- As the learning curve reduces capital costs, the need for government support will reduce and ultimately no longer be required.
- Long-term, fixed price, government supported contracts provide a strong basis for financing. As that support is removed, investors will be required to accept price risk for an emerging green hydrogen market. This would lead to lower DERs and could slow investment until commercial long-term contracts or a long-term futures market emerge.
- Green hydrogen is expected to become, eventually, a global, traded commodity. It is not expected that there will be a globally traded green hydrogen market until the 2040s at the earliest.
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