Hydrogen Hopefuls Advised to Focus on Offtake Amidst Funding Turbulence

With the fate of federal funding in limbo, Paul Browning advises companies with ambitions to scale hydrogen to “focus on your offtake right now.”

Browning, co-founding partner of Energy Transition Finance, was among several panelists at the recent World Hydrogen North America conference in Houston who emphasized the importance of securing offtake agreements to lock in financing, scale production and drive down costs.

The sector is not new, with hydrogen being used mainly in petroleum refining and ammonia production to make fertilizer, but efforts are underway to broaden hydrogen applications. As a low-emissions energy carrier, hydrogen is an option to replace higher-emissions fossil fuel sources where feasible in chemical and industrial processes, for energy storage or for transportation. High costs and infrastructure needs, however, pose challenges.

Some companies and countries with ambitions to lower emissions are seeking out hydrogen for its decarbonization abilities. Yet, offtake agreements are not evolving quick enough for some projects to reach final investment decisions (FID), according to Nicolas de Coignac, deputy CEO – Americas and hydrogen for electrolyzer designer and maker John Cockerill.

“It really depends on the regions of the world. I can tell you in India, for example, it’s going extremely fast. Middle East and North Africa, too,” de Coignac said. Some of the company’s U.S. customers have secured between 30% and 40% of their offtakes. “They need a little bit more before they reach FID, so it’s getting traction” but takes time.

U.S., abroad

Advanced hydrogen projects in North America are looking to incumbent sectors—such as refining, chemicals and fertilizer—and export opportunities for shipping and power, according to Brian Murphy, head of hydrogen and low carbon gas research for S&P Global.

“If we look at projects that are under construction or have FID, the U.S. is the largest single country for CCUS projects. We expect that to be true going forward,” Murphy said. “So, we are seeing a little bit of a bifurcation by technology where we have a significant number of electrolysis projects again in China and Europe. CCUS [is] really being driven by the U.S. There are key projects in Europe; a lot of that is retrofits of existing production in Europe.”

To reach FID, a project consortium needs a comprehensive approach.

“What we’re seeing for projects that take FID is essentially very well-developed project consortia where you have suppliers, potentially midstream as well as offtakers, all working together to develop a project, understand how costs are going to be divided, if there’s going to a price premium, how that price premium is supported, and get to a point where you’re signing secure, long-term offtake agreements,” Murphy said. “This is what we see really driving FIDs today, and part of that is industrial partners that are established players, maybe not in hydrogen, but in some adjacent sector extending into hydrogen and using that trust and credibility in order to bring a project to FID.”

Government support, such as tax incentives, also plays a role, but in many instances is not enough to close the cost gap between unabated hydrogen production and clean hydrogen production.

Andy Steinhubl, hydrogen program chair at the Center for Houston’s Future, pointed out how an earlier panel’s discussion on hydrogen’s role in North America turned to supplying Japan, South Korea and European markets (and California) and how economics drive decision-making.

“If you start with, say, an assumption of $1 [per] kilogram hydrogen,” which is difficult to get to for green hydrogen without a production tax credit and perhaps somewhat easier for blue hydrogen, he said, “that’s equal to $8/Mcf natural gas. So, if your alternative is Henry Hub natural gas, obviously that’s a huge gap.”

However, in Europe, natural gas is about $15/MMBtu. “So, OK, now I’ve got 8 versus 15, but … I’ve got to convert it into a carrier so I can move it over to Europe,” Steinhubl explained. “Currently, the prevailing technology is ammonia. Well, that’s $1, or so, a kilogram, then I’ve got to ship it and then I got to bring it over into a terminal in Europe. Now, if I want the hydrogen molecule, say I’m a refiner, I’ve got to crack it back and that’s pretty expensive.”

Japan is considering bringing in ammonia to co-fire with their coal power system—avoiding ammonia cracking—to help lower emissions, he added.

Costs don’t stop there.

A bigger picture

Companies that choose to use hydrogen and pursue offtake agreements also must consider costs of adoption. Steel makers opting to swap out petroleum coke with hydrogen to lower emissions while making steel would require new processes and new plants, Steinhubl said.

“There’s a lot of cost on the end-use side,” when switching to hydrogen versus existing solutions, he added.

Natural gas could provide another pathway to more hydrogen use.

“We’re all looking for that large-scale creditworthy offtake, because that’s what we know makes projects happen,” said Yuri Freedman, senior director of business development at SoCalGas. “It gets capital, gets technology competing, gets the scale.”

Freedman said blending of hydrogen and natural gas networks can quickly create large-scale offtake. “If we need to move fast, which scientists tell us we do, creating that offtake through the purchasing of hydrogen by natural gas utilities is a certain way to do this.”

He added that 1% blending of hydrogen into SoCalGas’ network will create tens of thousands of tons per year of hydrogen demand. “We ultimately need to figure out what is safe.”

Some places have strong demand-side policies in place to build the hydrogen economy, according to Naomi Boness, managing director for the Standard Natural Gas Initiative.  She highlighted Japan’s contract for difference subsidy program, which covers the cost gap for 15 years between low-carbon hydrogen and fossil fuel equivalents. In the U.S., the EFI Foundation is leading the Hydrogen Demand Initiative consortium to “design demand-side support measures to facilitate purchases of hydrogen produced by H2Hub-affiliated projects,” according to its website.

“There is a lot of traction with some of the data center operators who have shareholders that do care about the carbon intensity of their power, and I think this is a place that is ripe with opportunity,” Boness said.

Hydrogen is at the heart of the Advanced Clean Energy Storage project in Delta, Utah (ACES-Delta). The hydrogen storage project came together before the IRA with an offtaker; a location with access to renewable energy, water, storage; and infrastructure that includes pipelines near the offtaker’s fence line. The project, being developed by Chevron Corp. and Mitsubishi Power, will provide fuel via pipeline for Intermountain Power Agency’s 840-megawatt combined cycle gas turbine power plant, which is adjacent to the ACES Delta hub. The gas turbines will run on 30% hydrogen fuel at startup in 2025, but that percentage could increase to 100% by 2045.

Browning is former CEO of Mitsubishi Power Americas.

“What we did with the Advanced Clean Energy Storage project, is we told our offtaker [that] you can have whatever upside comes out of the IRA,” Browning said. “So, we have an agreement and part of the agreement is you get the upside of the Inflation Reductions Act. I suggest trying to get that kind of an offtake arrangement in place while you’re waiting.”