HOUSTON — At the 2023 CERAWeek energy conference, hydrogen was all the rage. The fuel seen by many as ultimately the only real path for the Class 8 trucking industry to join the energy transition away from oil emerged from a legislative victory in Washington with the passage of the Inflation Reduction Act (IRA) and his generous motives. for the production of hydrogen from renewable fuels, the 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 hydrogen’s potential in transportation and other end-use markets. But there was clearly a level of attention that was far less visible just 12 months earlier.
That led a panel moderator, Peter Gardett of S&P Global Commodity Insights (which produced the conference), to ask: Is there a case for hydrogen? (NYSE: SPGI).
And during the Hydrogen Hub panels, the panelists presented several bull cases. Much of the concern in the hydrogen community stems from the fact that the details of the tax breaks under the IRA have not been finalized.
When hydrogen was under discussion at CERAWeek in 2023, the number the presenters focused on was simple: One kilogram of hydrogen produced through renewable energy sources, designated as green hydrogen, would get a $3 tax break. This was seen as equivalent to a $3 per gallon downward move to price parity with diesel, the key benchmark.
Details on the proposed regulation were released in late December, and a subsequent comment period ended in February. The industry is awaiting the final rule.
But the devil is in the details and this preoccupied several Hydrogen Hub presenters.
The section of the tax code that will affect hydrogen production is known as 45V. According to Resources for the Futurea Washington-based interest group focused on environmental issues, one of the factors being considered in the Treasury Department’s final rule on 45V is that the green hydrogen tax credit could only be claimed if it could be shown that the green The electricity used to produce the hydrogen was produced at the same time as the hydrogen.
Rotating turbines that produce fully renewable electricity at the same time as hydrogen can be “proved” through the use of energy performance certificates, according to Resources for the Future. With EACS, there can be proof of “hourly matching”. But EACs were previously seen as the tool to simply show that somewhere in the supply chain, renewable energy had been used to generate electricity and that would be enough to claim the credit. This may no longer be the case.
I’m worried about the “hourly match”
The hourly matching requirement is seen as a major problem by those involved in the development of the hydrogen market.
Scott Pearl, director of Global Infrastructure Partners on a panel titled Innovative Hydrogen Financing — the one moderated by Gardett — didn’t mince words about the impact of hourly matching. “It could add 40% to 50% to the cost of projects,” he said.
If hourly matching were imposed, a hydrogen production facility such as an electrolyzer would not be able to claim the tax credit if it could not show a link to green electricity production. According to Resources for the Future, this proof now comes through the use of energy performance certificates.
Anthony Omokha, managing director at Ares Management Corp. (NYSE: ARES), which is a major investor in a hydrogen project in Texas, was blunt. “When it comes to real hydrogen production on a large scale, we need 45V to be in place,” he said.
But it may not stop there. Despite repeated statements throughout the day that there is sufficient demand, Omokha said, “we may need additional demand-side subsidies to unlock these projects.”
This issue came up repeatedly during the Hydrogen Hub sessions: the uncertainty of demand faced by the projects. That the end demand exists in a variety of applications was not a concern, the panelists said.
It was that developers of hydrogen production projects, such as electrolytes, need to find financing for a “bankable” project – a word that came up several times – and one of the best ways to achieve this is a long-term purchase commitment for the production of the project. But this is not a feature of the hydrogen market, which can be considered little more than non-existent.
The need for long-term contracts is also fueled by the fact that market signals are not fully transparent. Long-term offtake agreements are needed, Omokha said, because “there is no spot market for low-carbon hydrogen today.”
The disincentive to sign up in the long run
Part of the problem is that the hydrogen community generally sees the price curve going down over time — if it doesn’t, there will essentially never be a market for it — so committing to a long-term purchase agreement now could be market on the blouse.
Kelly Cummins, the acting director of the Office of Clean Energy Demonstrations at the US Department of Energy, summed up that view. “The problem we have with these big hydrogen hub projects is that the people building the infrastructure need long-term, bankable contracts,” he said. “But concessionaires don’t want to sign up when they know the price of hydrogen is likely to drop.”
The analogy with early LNG
However, there were several references throughout the day to the fact that LNG faced a similar landscape 20 to 30 years ago: no spot market, manufactured price benchmarks based on the value of alternative fuels and the need for developers to find long-term purchase agreements of 20 years or more to proceed. Now, there is a robust LNG market with price transparency.
Austin Knight, vice president of hydrogen at Chevron New Energies, noted this story and expressed a wish: “We hope it will move faster for hydrogen than for LNG,” he said.
Cummins’ remarks were made to a panel on the status of DOE-approved US hydrogen nodes since the IRA was approved. There are seven of themawarded in October, across the country.
Those projects are now in the planning stages, Cummins said. Each has a unique aspect that led to its award. For example, he said, the California hub may benefit from the state’s advanced clean fleet mandates, while the Appalachian hub may benefit from being in the middle of a region with abundant, relatively cheap natural gas and labor that, as he said, he is “in transition”. (Cummins did not specifically mention carbon but it was implied).
But building new hubs is not imminent, Cummins said, because the DOE now wants to focus on finding buyers to produce the hubs. “We will withdraw some of the remaining hydrogen hub funding because we want to help on the demand side,” he said. That help could come in the form of support to help establish a sustainable price for hydrogen that would make the project more – to repeat the word of the day – “usable”.
In response to Gardett’s question about the bull case for hydrogen, Pearl said the “low-hanging fruit” would be to replace gray hydrogen — produced with natural gas but without carbon capture — with blue hydrogen, which also extracts hydrogen from water but with carbon sequestration to minimize the carbon footprint of the process.
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