Key issues for hydrogen developers

Key issues for hydrogen developers

June 23, 2023 | By James M. Berger in Los Angeles

The hydrogen offtake agreement is the most important component of developing a hydrogen project. There is no merchant market for hydrogen, so a project developer will need a long-term hydrogen offtake agreement in order to finance a project.

Few Buyers

However, hydrogen buyers can be hard to find. The largest use of hydrogen is currently in oil refining, followed by ammonia and methanol production. The next sectors that are potential buyers are steel, cement and sustainable aviation fuel production.

Most of the current hydrogen used by these industries is made from fossil fuels, usually through steam methane reforming of natural gas.

Many current users of hydrogen desire — or are under political or regulatory pressure — to switch to green hydrogen. This creates an opportunity for a project developer to find a quality counterparty.

If the hydrogen economy grows as many expect, there will be other potential buyers in the future, such as long-distance trucking, aviation and energy storage. For now, developers should focus on targeting the industries that already use significant amounts of hydrogen as potential buyers.

Once a project developer finds a buyer, the creditworthiness of the buyer is vitally important. Financiers will require a creditworthy buyer or a buyer with a creditworthy parent that can provide a guaranty or other credit support. Without this, it may be impossible to finance a project.

Next, the terms and conditions of the offtake agreement will be important.

Financiers are likely to amortize the debt based on the length of the agreement, so the longer the agreement, the more debt that will be available. The more debt available, the less equity a sponsor will need, although financiers will require some minimum amount.

Financiers will also examine the amount of fixed revenue likely to be generated under the offtake agreement. This can take many different forms such as a fixed reservation payment or capacity or demand charge, but the most common form is likely to be a take-or-pay obligation.

With a take-or-pay obligation, the buyer is required either to take the hydrogen and pay for it or just pay for it. This ensures that a project can expect a minimum level of revenue. The buyer will want a minimum production guarantee to ensure it receives an agreed-upon minimum amount of hydrogen every year.

This form of offtake requires a balancing act by the project developer. A developer will want to increase the minimum volume to increase revenue. However, because these types of projects are new, the developer may want flexible output targets in case there is more downtime at the plant than expected so that the developer can avoid penalties for underperformance.


The location of a project could be the next most important issue.

Some developers try to site projects close to buyers to minimize the need to transport hydrogen. Others site projects close to the inputs, such as electricity and water for electrolysis or biomass or other materials for gasifiers. There is no right answer.

The two main hydrogen delivery methods are by pipeline and truck. Transporting hydrogen by pipeline is significantly less expensive than by truck, but creates other issues. Hydrogen is less dense than gas and escapes more easily. It can corrode metal. There is also not currently any regulatory certainty around hydrogen pipelines, which is an obstacle to pipeline construction. The Federal Energy Regulatory Commission is expected to assert jurisdiction over hydrogen transmission. This will create regulatory certainty for pipeline developers.

Transportation of hydrogen by truck may be the only option if the end users are widely dispersed, such as hydrogen refueling stations. If the ultimate destination is overseas, then the hydrogen or ammonia will be piped to a port and loaded on a ship.

If the project is producing carbon dioxide that it intends to sequester, this adds additional complexity. This is another waste product that must be accounted for and it complicates siting decisions due to the very limited number of sites where sequestration is permitted and the need to pipe the carbon dioxide to the injection well. There are only a couple currently permitted wells in the country. Several dozen others have permit applications pending with the EPA.

Related to the location are the inputs needed for a successful project. An electrolyzer needs significant volumes of water. Gasifiers need whatever material will be converted into hydrogen and other gases (for example, waste or biomass).

Negotiating water rights can be tricky. Ownership of water depends on its location. Generally, the state owns surface water while groundwater is typically owned by the landowner.

Ownership of surface water cannot be conveyed, but a user can obtain rights to it by permit. Groundwater can be sold, but there can be other legal restrictions around its use.

If other inputs are needed, where will they come from and how will they be delivered are important considerations. Electricity is relatively easy to access. Biomass or other materials that are feedstocks for gasifiers must usually be trucked to the project. The number of trucks and the timing of deliveries may be regulated by the project permits. Heavy truck traffic creates safety and pollution issues that will be of concern to the local community.


Financiers care about the technology and pay close attention to how the construction, revenue and other project contracts fit together.

Some of the technology used to produce hydrogen is well established and has a long history. Other hydrogen production technology is newer. Financiers want proven technologies. The tax equity and debt markets do not take technology risk.

For projects using new technology, there must be a successful track record somewhere such as in Europe or Asia. An independent engineer must stand ready to explain the technology to the financiers. If the technical experts are uncomfortable with the technology, the financiers will remain on the sidelines.

A green hydrogen project is significantly more complicated than a typical solar or wind project.

Some hydrogen projects have fully wrapped construction contracts, meaning a prime contractor takes responsibility that the various pieces of the project provided by different vendors will work together when fully assembled. The exception is the electrolyzer because it is a packaged, modular piece of equipment. If the gold standard of a fully-wrapped construction contract is not available, then the developer usually must make do with different contractors for different parts of the project.

This creates risks as to timing, technology compatibility, finger-pointing and potential liquidated damages mismatches. All of these can be addressed by an experienced developer, but financiers will want an independent engineer to verify that all of these types of risks have been adequately mitigated.

The eventual financing of a planned project must be kept in mind at all times during development.

The developer must keep a close eye on the financeability of the project documents as each contract is negotiated. This means ensuring adequate cure periods when obligations are inadvertently breached, adequate liquidated damages, appropriate time frames and deadlines and limits on the ability of the counterparty to terminate the agreement.

The potential financial incentives, such as federal tax credits and state-level low carbon fuel standard credits need to be worked into the financial architecture of the deal. They can also enhance a project's economics.

Tax Credits

The most complicated part of the capital structure to account for is the federal tax credits for producing clean hydrogen.

Hydrogen producers can choose between an investment tax credit or a production tax credit. The ITC is taken in the year the project is placed in service. PTCs are claimed over 10 years on the hydrogen output.

The amount of the tax credit depends on the carbon intensity of the hydrogen being produced. To qualify for the maximum tax credit, the hydrogen production process must produce fewer than 0.45 kilograms of CO2-equivalent emissions per kilogram of hydrogen.

The emissions are measured on a lifecycle basis "well to gate" using the GREET model developed by the Argonne National Laboratory. The US Treasury is wrestling with a number of issues, including under what circumstances emissions from using direct grid electricity to run electrolyzers can be offset by buying renewable energy credits, or RECs, from owners of renewable energy power plants. (For more detail, see "Hydrogen Tax Credits" in the October 2022 NewsWire.)

If a developer chooses PTCs, it can also choose to have the IRS pay the cash value of the PTCs for the first five tax years after the hydrogen plant starts operating. After that, the PTCs could be sold to another company, but it would be at a discount. (For more detail, see "Transferability: Selling Tax Credits" in the March 2023 NewsWire.)

If the project will use clean electricity generated by a wind or solar project that is owned by an affiliate of the hydrogen plant owner, it will create a "section 707(b) issue." The owner of the wind or solar plant will not be able to claim tax losses on it. No losses can be claimed on property sold to an affiliate. This is complicating structuring of hydrogen projects. (For more detail, see "Section 707(b): Related-Party Electricity Sales" in the June 2021 NewsWire and "Another Utility Tax Equity Structure" in the February 2022 NewsWire.)

Finally, because the green hydrogen industry is still nascent, many developers partner with large, established companies that are sources of capital, equipment or construction expertise. If the partner will be a co-owner, then there will be a lot to negotiate, such as how to split responsibilities, protect each party's intellectual property, determine who owns newly-developed intellectual property, provide for downside protection in case one party fails to fulfill its obligations or fails to fund and decide on potential buy-outs.