Negotiating hydrogen contracts
By Rachel Crouch
Market standards for hydrogen revenue contracts remain malleable. The hydrogen market is set to undergo rapid change and expansion.
Long-term revenue contracts will be key for early low-carbon hydrogen projects to obtain financing, and developers and their potential customers are beginning to consider appropriate terms for offtake contracts.
This article explores key issues to be evaluated when negotiating such agreements.
Tolling v. Sale and Purchase
It is instructive to compare the nascent hydrogen offtake market to the LNG market. LNG projects have developed two principal models of revenue contracts: tolling agreements and sale-and-purchase agreements.
Under the LNG tolling model, an LNG facility provides natural gas liquefaction capacity to its customers. Each customer is responsible for sourcing natural gas, delivering it to the liquefaction facility, and shipping and marketing the LNG produced with that natural gas. The customer pays the liquefaction facility to convert gas belonging to the customer into LNG.
Similar to LNG, under a tolling model for blue hydrogen projects (where hydrogen is produced by reforming fossil fuels and then capturing carbon emitted from that process), the customer would buy the fuel and pay the hydrogen plant to convert it into hydrogen. Under a tolling model for green hydrogen (where hydrogen is produced from electricity and water through electrolysis), the customer would purchase electricity to be used at the electrolysis plant and potentially also supply the water to be used. It would supply these raw materials and pay the owner of the electrolyzer to convert the water into hydrogen and oxygen.
Under the LNG sale-and-purchase model, an LNG project either produces or purchases the upstream gas and is then responsible for transportation to the liquefaction facility, liquefying the gas and then selling it as LNG.
Similarly, a blue hydrogen developer would procure natural gas and then produce and sell hydrogen made from the gas.
Under a green hydrogen sale-and-purchase arrangement, a project developer would buy electricity and water. As with natural gas, the electrolyzer facility owner may procure electricity in several ways. It may buy electricity from a third party at arm’s length by entering into a corporate PPA with a renewable power project. Many corporate PPAs are “virtual” PPAs that act as price hedges. The actual electricity used is purchased in the spot market, but the virtual PPA is a means of fixing the price. Alternatively, the electrolyzer owner may play a role in the power production — because the same project company owns both the power plant and the electrolyzer, because the two plants belong to affiliates owned by a common sponsor, or because the power producer and the hydrogen producer have entered into a joint venture.
There are several factors to consider when determining whether a tolling or sale-and-purchase approach is preferable. First, the availability and terms of a PPA or other feedstock supply agreement will be better for the entity with a higher credit rating — whether that is the hydrogen customer or the hydrogen project company (or, in either case, a sponsor guarantor). Second, different counterparties will be differently disposed to enter into a separate PPA or other energy supply arrangement or to procure the water necessary for a green hydrogen project.
For example, customers that intend to use hydrogen for long-duration energy storage as a complement to electricity generation may be more inclined to choose a tolling model, since such customers have experience, resources or portfolio benefits that may make them better suited than an electrolysis project developer to enter into a PPA or other arrangement for electricity to supply to an electrolysis project.
Users of hydrogen for other purposes may be less motivated to do so. Moreover, independent renewable power producers viewing hydrogen as an extension of their business models may decide to develop a renewable power plant as part of a combined project with an electrolyzer.
In certain jurisdictions, particularly in western states, issues surrounding the party best suited to hold water rights will also need to be considered.
Hydrogen offtake contracts are likely to follow a take-or-pay or take-and-pay model so that there is a reasonably predictable revenue stream.
Under a take-or-pay agreement, the buyer and seller agree up-front on a specified contract quantity to be delivered on a periodic basis, and the buyer must either take delivery of that quantity (and pay for it) or pay the seller for any amount not taken, unless the failure is excused under the contract. If a buyer fails to take — but pays for — the full contract quantity, it may be entitled to a make-up quantity at a future date. Take-or-pay contracts are common in the LNG sector.
Under a take-and-pay contract, the buyer must take the agreed contract quantity and pay for it. Failure to take delivery will entitle the seller to remedies for the breach. Damages for failure to take may be contractually stipulated liquidated damages or general damages. Unless the contract provides for liquidated damages, seeking recovery for the breach may take considerable time and expense and will likely require the seller to demonstrate its efforts to mitigate losses as well as proof of actual loss.
Other alternative models for determining the quantity to be delivered exist for hydrogen contracts today that may not be bankable for green or blue hydrogen projects under development. For example, requirements contracts, under which the buyer and seller contract for the seller to fulfill the entire demand of a hydrogen-using project owned by the buyer, or contracts allowing the buyer to nominate different quantities of hydrogen from time to time and requiring the supplier to scale up or down in response, may be too open-ended to be palatable to project finance lenders.
To be bankable, hydrogen offtake contracts — especially for early hydrogen projects — will probably need to be either take-or-pay or take-and-pay (preferably with liquidated damages), for three principal reasons.
First, financiers will require a predictable revenue stream. Second, because there is no merchant market for hydrogen, selling hydrogen not taken and paid for by a customer will not be a straightforward proposition. Finally, in many cases, early green hydrogen projects may not be able to decrease the electricity they purchase under their PPAs without paying for it, resulting in relatively constant input costs and making it critical to have a reliable purchaser for the output.
There are currently no spot prices for hydrogen. Contracts for the sale of hydrogen produced from fossil fuels (which constitutes the vast majority of hydrogen sold today) are often based on the actual price of feedstock (usually natural gas), plus other fixed and variable costs and a profit element.
Until a benchmark price for hydrogen is adopted in the market, green and blue hydrogen contract prices may follow a similar formula based on fixed costs plus variable costs actually paid.
S&P Global Platts has launched regional hydrogen benchmark price assessments for different production pathways, including steam methane reformation, steam methane reformation with carbon capture and storage, proton exchange membrane electrolysis (called PEM electrolysis) and alkaline electrolysis. The Platts assessments are based on regional natural gas and electricity assessments, along with assumptions regarding capital and operating expenses. Platts has taken similar cost-based approaches in developing assessments for other non-liquid markets in the past. Offtake contracts for both green and fossil fuel-based hydrogen may look to the applicable regional Platts assessment in determining contract prices.
Given the projected rapid pace of development of the hydrogen market, parties may consider whether to include price review provisions in their offtake contracts. Under these provisions, the parties would review the price formula on an agreed periodic basis or upon the occurrence of certain triggers indicating a change of circumstances. These provisions should be considered carefully because price reviews are very susceptible to dispute, and there are unlikely to be objectively determinable spot prices to rely on by the time the opportunity for a price review arises under early green or blue hydrogen sale contracts.
Given the lack of a spot market for hydrogen and the challenge of transporting it over long distances, negotiating liquidated damages presents a challenge where substitute hydrogen — even traditional “grey” hydrogen produced from natural gas without carbon capture — is not readily available. In such instances, “deliver-or-pay” provisions for the failure of the seller to deliver the contract quantity of hydrogen that look to the cost of procuring alternative hydrogen may be deemed overly punitive.
Project owners and project finance lenders will naturally prefer long-term revenue contracts with customers with strong credit to support their commitments. (See “Emerging Opportunities in the Hydrogen Market” in the December 2020 NewsWire.) For many nascent hydrogen use cases, however, the customer may be a start-up company or even a special-purpose project company itself.
In these cases, traditional credit support in the form of a parent guarantee (if a creditworthy parent exists) or a letter of credit may be necessary to make the project bankable.
Project owners should also assess their project’s stakeholders to determine where a creditworthy entity may be able to back-stop a take-or-pay or similar obligation.
Even if the direct offtaker is not a creditworthy entity, it may have creditworthy customers as its clients — for example, where a start-up refueling company offtaker purchases hydrogen from a hydrogen project with the intention of reselling it to publicly owned bus operators. In this case, the stakeholders may contract for a look-through from the hydrogen project to the governmental entity, where the hydrogen project company may step into some or all of the refueling company’s rights to collect from the more creditworthy entity.
Conversely, for use cases where the end user is not creditworthy and cannot support a bankable hydrogen project, there may be a role to play for an intermediary trading company that is creditworthy or able to draw on adequate credit support.
Governments, multilateral institutions or export credit agencies aiming to get the clean hydrogen industry off the ground may also step in to provide guarantees or other credit support when there is not a bankable offtaker or end user.
When considering the size of a planned hydrogen project, developers may need to weigh the savings in capital expenditure per ton that will result from a larger scale against their ability to find a long-term revenue contract with a creditworthy offtaker for the entire projected output at the outset of development. In some situations, particularly where the project will be located close to multiple potential offtakers, the benefits of scale may be such that developers opt to develop hydrogen projects that are oversized compared to their initial offtake contracts.
When drafting hydrogen offtake contracts, parties should consider the appropriate allocation of the risk of disruptions to a project’s ability to obtain feedstock — be it natural gas, electricity or water.
Parties will need to address the effect of potential delays in completion of any project that will supply an input for producing hydrogen. Offtake contracts can be expected to specify a deadline for the first delivery of hydrogen. Delays may result in liquidated damages or termination rights. If a green hydrogen project is being developed alongside a new renewable energy power plant, the timing risk for the project is multiplied. In some cases, green hydrogen projects may also need to be undertaken together with water treatment or desalination projects, adding further timing risk.
Parties will also need to address the risk of an interruption of feedstock supply. LNG sale-and-purchase agreements again provide useful precedents for how this may be managed in hydrogen offtake agreements.
In LNG sale-and-purchase agreements, the non-availability of economically obtainable feedstock or the interruption of feedstock transportation is often explicitly excluded from the definition of force majeure. However, in many cases, force majeure under a gas supply or transport agreement will be force majeure under the corresponding LNG sale-and-purchase agreement if it results from an event that would also satisfy the definition of force majeure under that LNG sale-and-purchase agreement. Similar provisions could be adopted with respect to electricity or natural gas for hydrogen revenue contracts.
Developers and their financiers should make an effort to ensure that the force majeure provisions in hydrogen project PPAs or other supply agreements and their offtake agreements are back-to-back to the extent possible, both when it comes to extensions of commercial operation deadlines and to interruption of supply.
Although government support frameworks are still developing for green and blue hydrogen, most if not all early projects will benefit from a subsidy or tax incentive that will underpin the economics of the revenue contracts. The cost of complying with an offtake contract will also be affected by law, regulation and government policy — for example, with respect to safety, gas specifications and export or import restrictions. Hydrogen offtake contracts will need to specify clearly which counterparty bears which change-in-law risks.
Today, hydrogen projects are often located at or near their offtakers’ plants — usually petroleum refineries or ammonia production facilities. Most early green and blue hydrogen projects will probably follow this model, although market participants are looking ahead to the transportation of hydrogen through pipelines (either blended with natural gas or on its own), on trucks or on ships. Any time a hydrogen project is not co-located with the offtaker, the offtake contracts will need to specify clearly the point of transfer of title and risk of loss. Hydrogen project developers and their customers should consider which counterparty is the best positioned to store, transport and deliver the hydrogen and to bear risks associated with those activities.
Green or Blue Certification
It will take time for green and blue hydrogen to become cost-competitive with hydrogen produced via reformation of fossil fuels without carbon capture. Companies buying hydrogen with the objective of decarbonizing their energy use or governments supporting the development of a low-carbon hydrogen economy should, for at least the next decade, expect to pay a premium for low-carbon hydrogen purchases.
To allow for price differentiation, it will be necessary that green or blue hydrogen be certified as such or otherwise be demonstrably derived from renewable energy or complemented with carbon capture.
Representations and warranties as to the electricity or carbon capture associated with hydrogen production may be included in hydrogen offtake agreements.
Perhaps more importantly, third-party certifications may be required. An early example of this is the European CertiHy scheme, which provides green and low-carbon guarantees of origin.
In the case of blue hydrogen, in the absence of government-imposed standards, counterparties may look to standards developed in recently signed LNG sale-and purchase agreements that incorporate statements of greenhouse gas emissions. Credit given for carbon captured will need to account for carbon re-released through use or leakage. This issue is under scrutiny by developers looking to take advantage of the section 45Q federal tax credit.
California has developed a low-carbon fuel standard (LCFS) under which suppliers of low-carbon fuels earn credits. The value of the credits is negatively correlated to the carbon intensity of the fuel. (See “Financing California hydrogen projects using LCFS credits” in the December 2020 NewsWire.) These credits may do away with the need for other forms of carbon verification in the market for hydrogen as transport fuel in California and could provide a model or reference point for certifications or representations in bespoke transactions in other markets.
National standards for differentiating low-carbon hydrogen from traditional carbon-intensive hydrogen will need to be developed by governments or third parties. International coordination will be necessary to develop rules and standards as export markets develop.