HOUSTON — At CERAWeek’s energy conference in 2023, hydrogen was all the rage. The fuel that is seen by many as eventually the only real pathway for the Class 8 trucking sector to join the energy transition away from petroleum was coming off a legislative victory in Washington with the passage of the Inflation Reduction Act (IRA) and its generous incentives for producing hydrogen from renewable fuels, so-called green hydrogen.
A year later, at CERAWeek 2024, a parade of presenters at the conference’s Hydrogen Hub still said all the right things about the potential for hydrogen in transportation and other end-use markets. But there was clearly a level of caution that had been a lot less visible just 12 months earlier.
It led one panel moderator, Peter Gardett of S&P Global Commodity Insights (which produces the conference), to ask: Is there a bull case for hydrogen? (NYSE: SPGI).
And over the course of the Hydrogen Hub panels, participants laid out numerous bull cases. Many of the concerns within the hydrogen community stem from the fact that specifics of the tax breaks under the IRA have not been finalized.
When hydrogen was under discussion at CERAWeek in 2023, the number that presenters focused on was simple: A kilogram of hydrogen produced through renewable energy, qualifying as green hydrogen, would get a tax break of $3. That was seen as equivalent to a $3-per-gallon downward move toward price parity with diesel, the key benchmark.
Details in the proposed regulation were released in late December, and a subsequent comment period ended in February. The industry awaits the final rule.
But the devil is in the details, and that’s what concerned several Hydrogen Hub presenters.
The section of the tax code that would impact hydrogen production is known as 45V. According to Resources for the Future, a Washington-based interest group focused on environmental issues, one of the factors being considered at the Treasury Department for its final rule related to 45V is that the tax credit for green hydrogen could be claimed only if it could be be shown that the green electricity used to produce the hydrogen was produced in the same hour as the hydrogen.
Spinning turbines producing fully renewable electricity at the same time hydrogen is being produced can be “proven” through the use of energy attribute certificates, according to Resources for the Future. With EACS, there can be proof of “hourly matching.” But EACs previously had been viewed as the tool to just show that somewhere in the supply chain, renewable energy had been used to generate electricity and that would be enough to claim the credit. That may not be true anymore.
Worried about “hourly matching”
Requiring hourly matching is viewed as a significant problem by people involved in growing the hydrogen market.
Scott Pearl, a principal at Global Infrastructure Partners on a panel titled Innovative Hydrogen Financing — the one moderated by Gardett — did not mince words about the impact of hourly matching. “It could add 40% to 50% of the cost of the projects,” he said.
If hourly matching is enforced, a hydrogen production facility like an electrolyzer could not claim the tax credit if it couldn’t show a link to green electricity production. According to Resources for the Future, that proof now comes through the use of energy attribute certificates.
Anthony Omokha, a managing director at Ares Management Corp. (NYSE: ARES), which is a major investor in a Texas hydrogen project, was blunt. “When it comes to truly making hydrogen at large scale, we need 45V to be in place,” he said.
But it might not stop there. Despite repeated statements during the day that there is adequate demand, Omokha said, “we may need additional demand-side subsidies to unlock these projects.”
That issue came up repeatedly during the Hydrogen Hub sessions: the uncertainty of demand that projects face. That ultimate demand exists in a variety of applications was not a concern, panelists said.
It was that developers of the hydrogen production projects like electrolyzers need to find funding for a “bankable” project — a word that came up several times — and one of the best ways to get that is a long-term purchase commitment for the project’s output. But that is not a feature of the hydrogen market, which might be viewed as little more than nonexistent.
The need for the long-term contracts is fueled also by the fact that market signals are not fully transparent. Long-term offtake deals are needed, Omokha said, because “there is no spot market for low-carbon hydrogen today.”
The disincentive to sign up long-term
Part of the problem is that the hydrogen community generally sees the price curve bending down over time — if it doesn’t, there essentially will never be a market for it — so committing to a long-term purchase agreement now could be buying at the top.
Kelly Cummins, the acting director of the Office of Clean Energy Demonstrations at the U.S Department of Energy, summed up that view. “The problem we’re facing with these large hydrogen hubs projects is that the people building the infrastructure need bankable long-term contracts,” she said. “But the offtakers don’t want to sign up when they know the price of hydrogen is likely to decrease.”
The analogy to early LNG
However, there were several references over the course of the day to the fact that liquefied natural gas faced a similar landscape 20 to 30 years ago: no spot market, contrived price benchmarks built off the value of alternate fuels, and the need for developers to find long-term purchase agreements of 20 years or more to proceed. Now, there is a robust spot LNG market with price transparency.
Austin Knight, the vice president of hydrogen at Chevron New Energies, noted that history and expressed a wish: “We’re hoping it moves faster for hydrogen than it did for LNG,” he said.
Cummins’ remarks came at a panel about the status of the U.S. hydrogen hubs approved by the DOE since the IRA was approved. There are seven of them, awarded in October, stretching across the country.
Those projects are in the design phase now, Cummins said. Each has a unique aspect that led to its being awarded. For example, she said, the California hub can benefit from the state’s advanced mandates on clean fleets, whereas the Appalachian hub can benefit from being in the middle of an area with plentiful, relatively cheap natural gas and a workforce that, as she said, is “in transition.” (Cummins did not mention coal specifically but that was implied).
But setting up new hubs is not imminent, Cummins said, because the DOE now wants to focus on getting buyers for the hubs’ output. “We’re going to pull back on some of the remaining hydrogen hub funding because we want to help on the demand side,” she said. That assistance might come in the form of support to help create a sustainable price for hydrogen that would make the project more — repeating the word of the day — “bankable.”
In response to the Gardett question about the bull case for hydrogen, Pearl said the “low-hanging fruit” would be to displace gray hydrogen — produced with natural gas but without carbon capture — with blue hydrogen, which also extracts hydrogen from water but with carbon capture to minimize the carbon footprint of the process.
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