Clean hydrogen has a serious demand problem

Canary Media thanks Verdagy for its support of the Clean Hydrogen series.

The U.S. now has the world’s most lucrative incentive for making clean hydrogen, a tool that should cause the production of the fuel to surge in the years to come. 

But what’s supply without demand? Or, to put it more plainly: Who’s going to buy all the cheap clean hydrogen the U.S. is gearing up to make?

It’s far from clear how the demand side of the clean hydrogen economy will evolve to match the millions of tons of supply set to be unleashed by the Inflation Reduction Act’s 45V production tax credits. Those credits could direct hundreds of billions of dollars toward electrolyzers powered by carbon-free electricity — and, potentially, fossil-gas-fed hydrogen facilities combined with carbon capture — over the coming decades.

Clean hydrogen could eventually help decarbonize a host of industries, ranging from steelmaking to heavy-duty trucking. To serve its most immediate role in fighting climate change, however, low- or zero-carbon hydrogen must replace the roughly 95 million metric tons per year globally — and about 10 million metric tons per year in the U.S. — of dirty fossil-fuel-derived hydrogen already consumed for refining, fertilizer and chemicals production.

That’s exactly where Ben Alingh, co-founder and CEO of Monarch Energy, sees the near-term future of the industry.

Monarch Energy has raised $25 million in equity financing from energy infrastructure developer and owner LS Power, which plans to invest up to $400 million in projects by Monarch. But while most of the hydrogen hubs across the country have identified a panoply of end uses for the hydrogen they plan to produce, Monarch is specifically focused on decarbonizing the existing $20 billion U.S. hydrogen production market. 

The company will focus its first efforts on the U.S. Gulf Coast, where the existing hydrogen industry is concentrated. That includes a $426 million facility in Ascension Parish, Louisiana to make green hydrogen for a wide range of industrial and chemical processes.

Alingh, who previously worked on renewable energy development at Ørsted and Enel Green Power, said Monarch has a 4.5-gigawatt pipeline of projects in development across the U.S. But the company’s outreach efforts to attract new users have been minimal: ​“We’re not spending a lot of time telling people why they should be using hydrogen if they aren’t using it already.”

Monarch is not alone in focusing on existing hydrogen users. The industries using dirty hydrogen today are also among the world’s most heavily polluting, making them a key target for climate activists. Even environmental watchdogs who fear the influence of the fossil fuel industry in clean-hydrogen policy agree that today’s dirty hydrogen must be replaced with cleaner alternatives.

But just because the approach is smart doesn’t mean it will be easy. It will take more than cheaper clean hydrogen to convince existing users to make the switch. They’ll need far more certainty of production at the quantities they need, delivered at the steady, uninterrupted paces required for their particular uses. And they’ll need the infrastructure — pipelines and storage facilities — to move clean hydrogen from where it’s made to where they use it.

Outside of existing hydrogen production and consumption hubs like the U.S. Gulf Coast, these conditions don’t yet exist. And without them, it will be hard for the sky-high policymaker expectations and investment plans of the past few years to come to fruition.

Convincing offtakers to get on board

Despite the massive new subsidies aimed at supercharging clean hydrogen production, some experts think a booming clean hydrogen economy is far off. The International Energy Agency has cut its growth forecasts for the industry significantly over the past year, as have a number of other industry analysts.

Michael Liebreich, head of Liebreich Associates and co-founder of clean energy analysis firm BloombergNEF, recently highlighted the gap between government clean-hydrogen production targets and reality. BNEF has tracked 47 million metric tons of hydrogen production capacity that could ​“in theory” come online by 2030, he wrote. But of that, ​“just 1.5 million tons worth of projects have reached final investment decision or are already producing.”

The key driver of this disconnect is the lack of offtake agreements — the contracts needed for developers to secure financing for projects.

“Offtake is everything in this market,” Alingh said. ​“There’s no shortage of places you can physically make green hydrogen, at an attractive price, in a vacuum. The issue is, is there someone willing to pay you for it? And not just one time, but in a long-term contract with an investment-grade partner on the other side of that.”

So far, just 7.9 million metric tons of clean hydrogen production has identified prospective buyers, per a November report from BNEF. Of that amount, binding contracts represent only 13 percent, or 1 million metric tons per year. Another 7 percent ​“are pre-contractual agreements with a solid chance of becoming binding contracts,” according to BNEF. The rest may or may not eventually become binding.

The U.S. Department of Energy’s Clean Hydrogen Strategy and Roadmap report, published in June, points out a similar disconnect. Of the roughly 12 million metric tons per year of clean hydrogen production capacity announced in the U.S. at that time, only about 10 percent had reached a final investment decision, ​“largely due to the lack of long-term offtake” agreements.

“The high-level takeaway,” Xitong Gao, senior research associate at BNEF, told Canary Media, is ​“that we have far less demand than supply.”

Of BNEF’s global tally of offtake agreements, roughly 40 percent are for existing emissions-heavy uses that now rely on hydrogen from fossil fuels. Only about 15 percent is headed to other potential uses like shipping and aviation fuels, road transport and manufacturing, while a whopping 43 percent is ​“unspecified.”

But as BNEF’s Gao highlighted, while those industries make up a larger share of total clean-hydrogen contracts, their share of binding offtake agreements is lower than the proportion of binding agreements in other sectors such as shipping and aviation.

In other words, industries that already use gray hydrogen produced with fossil fuels have been less eager to commit to clean hydrogen than industries that aren’t yet able to actually put the hydrogen they’re agreeing to buy in the future to real-world use.

The barriers to decarbonizing today’s dirty-hydrogen demand

There’s a good reason why existing gray-hydrogen buyers are less eager to embrace the clean version. That would be the so-called ​“cost to switch” — an expense that isn’t captured in the top-line figures typically used to compare the price of dirty hydrogen to cleaner alternatives.

Right now, gray hydrogen in the U.S. costs between $1 and $1.50 per kilogram, whereas clean hydrogen costs $5 per kilogram and up. The Inflation Reduction Act’s 45V incentives, along with its incentives for building clean power, are expected to bring clean hydrogen within striking distance of that gray-hydrogen cost and even undercut it in some cases.

But an analysis published last February by the EFI Foundation, the nonprofit think tank co-founded by former Energy Secretary Ernest Moniz, finds that these supply-side cost reductions won’t be enough on their own. Instead, for industries using gray hydrogen today, ​“clean hydrogen costs may be competitive in the $0.27–$0.90 range,” the report states — specifically, 90 cents per kilogram for the steel industry, 80 cents per kilogram for ammonia production, 50 cents per kilogram for refining and 27 cents per kilogram for methanol production.

Why do these industries need clean hydrogen to be not only cheaper than the dirty hydrogen they’re already using, but much cheaper?

The answer is complicated, said Alex Kizer, the EFI Foundation’s chief operating officer. But it boils down to the fact that existing hydrogen sources are integrated into current systems and business models, making them cost-competitive and secure for the industries that use them. Retrofitting facilities, building new infrastructure and securing new sources of supply — all required to switch to clean hydrogen — add the type of new risks and uncertain costs that companies prefer to avoid.

EFIF’s chart of U.S. hydrogen use today provides a glimpse into the complexities of inserting clean hydrogen into existing dirty-hydrogen supply and consumption chains.

Of the roughly 10 million metric tons of hydrogen produced in the U.S. annually, about a quarter is made as a byproduct of other chemical and oil refining processes and used on-site. A significant portion of gray hydrogen is ​“captive” production — that is, made on the same site by the same company that is using it. 

In other words, industries that use hydrogen today are already making it themselves or buying it via long-standing partnerships. Tearing those up and replacing them with a new source of hydrogen — one for which no clear market structures or delivery infrastructure yet exists — is, ironically, a harder sell than buying clean hydrogen is for industries that are just starting to think through how they’ll source it, transport it and use it. 

The problem is even more dire when you zoom in on the biggest user of hydrogen today: oil and gas refineries. If this group decarbonized even half of its current hydrogen consumption, it could reduce global carbon emissions by an amount roughly equivalent to the entire U.K.’s emissions footprint, according to the Clean Air Task Force. 

But roughly two-thirds of the hydrogen used by refineries is supplied from on-site byproduct processes and is ​“unlikely to be replaced by low-carbon hydrogen,” according to analysis firm Wood Mackenzie. The rest is produced from fossil gas, over which refiners often have direct control.

That doesn’t mean that every oil refiner will snub lower-carbon hydrogen. In fact, the largest hydrogen electrolysis project operating in the world today is a 260-megawatt project built by Chinese state-run oil company Sinopec. 

But the International Energy Agency is tracking only a limited number of planned clean-hydrogen projects to serve refineries, amounting to 1.3 million metric tons of annual production by 2030. 

Most of those are likely to happen in the European Union. In September, French oil major Total issued a call for 500,000 metric tons per year of green hydrogen made using renewable energy to replace the gray hydrogen it uses in its six European refineries — one of the largest such procurement solicitations for clean hydrogen yet announced. 

Major emitters in Europe must pay for emissions under the EU’s Emissions Trading System, the world’s biggest carbon market, putting a hard value on investments to reduce them. Also, major gray-hydrogen users in the EU are bound by mandate to source a rising portion of that supply from clean sources starting later this decade. 

The U.S. lacks any such requirements, giving domestic refineries little reason to seek out more expensive sources for the hydrogen they need. 

Fertilizer: A major opportunity complicated by embedded infrastructure

Similar issues — higher costs, process inertia and a lack of demand-side incentives — apply to the next-biggest user of dirty hydrogen: the fertilizer industry.

The world makes about 190 million metric tons of ammonia per year today, according to the Clean Air Task Force. Of that, about 30 percent is made from hydrogen made from coal, mainly in China, while the rest is made from hydrogen made from fossil gas. Of all the ammonia produced globally, about 70 percent goes to fertilizer production.

Nearly half of the contracted low- and zero-carbon hydrogen in BNEF’s offtake database is planned to be delivered as ammonia. While ammonia can also be a carbon-free fuel for ships, the emphasis on ​“green ammonia” production among early-stage hydrogen production plans is likely driven by appetite from existing industrial applications, per the IEA, with fertilizer production particularly well suited to ​“absorb a significant share of the supply.”

Indeed, fertilizer is driving a lot of U.S. clean hydrogen plans. New Fortress Energy’s Beaumont, Texas project has an offtake agreement with OCI, a Netherlands-based global chemical company and fertilizer producer. Illinois-based CF Industries, another major fertilizer producer, plans to invest up to $4 billion in two large-scale low-carbon ammonia production sites in Louisiana’s Ascension Parish — the same area being targeted by Monarch Energy.

Green hydrogen and ammonia are also being explored by the massive fertilizer producers dotting the Midwest U.S. CF Industries’ first green-ammonia production site in Donaldsonville, Illinois is expected to come online later this year. The company has announced plans for others in Oklahoma working with renewable energy developer NextEra. And Monolith, a company backed by a $1 billion DOE loan guarantee for its ​“turquoise hydrogen” methane pyrolysis plant in Nebraska, plans to make ammonia for Midwest fertilizer production. 

The challenge for clean hydrogen in fertilizer production, as with refining, is overcoming the status quo, EFIF’s Kizer explained. Unlike refineries, fertilizer-makers don’t control the fossil gas resources that feed their hydrogen needs. But they do have well-established structures for getting and using it that complicate making the switch to a cleaner alternative.

Today, some U.S. hydrogen is sold by ​“merchant producers” — either industrial gas companies or refineries that sell hydrogen they produce in excess of their current needs to other users. The remainder is made and used within the same ​“highly integrated facilities” like refineries, methanol plants and ammonia plants, he said.

These integrated plants are designed to take in fossil gas, turn it into hydrogen, and then convert that hydrogen to ammonia, he said. Switching to clean hydrogen would require fertilizer plants to reduce or halt their use of this existing equipment, which they’ve already spent money on, and build new infrastructure.

“There are significant dimensions of these chemical processes that are interrupted when new clean-hydrogen supplies emerge from an external provider. There are costs to switch that are material for these asset owners,” according to Kizer.

Until green-hydrogen producers can lay out a credible pathway to undercutting gray-hydrogen costs at these harder-to-reach ​“cost-to-switch” price points, any clean hydrogen targeting the industry will carry with it a ​“green premium.”

Monarch Energy’s Alingh conceded that his company and other clean-hydrogen producers will need to contend with these challenges. Existing hydrogen users are ​“extremely sophisticated buyers of industrial commodities,” he said. ​“They’re primarily focused on how they can save on costs and pass those cost savings on to their customers.”

They’re also unlikely to sign long-term contracts for clean hydrogen without the pipelines to deliver it to them as easily as they can get fossil gas today.

Today’s hydrogen pipeline and storage infrastructure, which is almost all located in the U.S. Gulf Coast, is owned and operated by existing hydrogen producers and consumers. Finding ways to open them up to clean hydrogen will likely be complicated by the existing ownership and contractual structures that govern how they’re used today.

Some legacy hydrogen producers that own infrastructure in the Gulf Coast region, like Air Liquide, are embracing clean hydrogen. But there’s no guarantee every incumbent will do the same.

Chasing the ​“green premium”

Most proposed U.S. clean-hydrogen production sites are ​“chasing a green-premium user to help cover project risk,” Kizer said. Today, those users are predominantly European companies aiming to manage carbon costs and meet European Union mandates.

Under current EU mandates, 42 percent of hydrogen used in industry must be renewable by 2030, said Drake Hernandez, associate principal in energy at Charles River Associates. In the U.S., by contrast, ​“there’s still nothing by the way of a top-down push to say, ​‘You have to start consuming clean hydrogen.’”

The early-stage offtake agreements taking shape in Europe are right now driven by the European Union’s carbon emissions penalties rather than by its green premium structures, noted Dieter Keller-Giessbach, a vice president at Charles River Associates’ energy practice. But that could change as European governments begin to jump-start market structures that can bridge the current gaps between sellers and buyers. 

In November, the EU opened bidding for its €800 million ($867 million) European Hydrogen Bank pilot auction, meant to connect clean hydrogen producers with offtakers. The auction, which could expand to a larger €3 billion ($3.25 billion) round in 2024, will offer a fixed green premium for production over 10 years, with the amount of the premium to be set by comparing supplier prices against bids from would-be offtakers. 

Such models could ​“get people to invest in a new facility that may not have the same business-model questions and concerns that some of the existing plants do,” Kizer said.

DOE’s Clean Hydrogen Strategy and Roadmap report highlights the need for similar structures in the U.S.

The core federal policy aimed at solving this supply-demand disconnect is the $7 billion in DOE grants to develop seven ​“hydrogen hubs” across the country. EFIF’s report cites these hubs as a key step in aligning hydrogen supply and demand, with the potential to ​“integrate a broad constellation of projects and activities that comprise the hydrogen value chain.”

But the Biden administration appears aware that the hubs alone can’t bridge the gap between demand and supply. In July, it announced plans to provide an additional $1 billion to an as-yet-unspecified ​“demand-side initiative to support” development at the regional hydrogen hubs, with the goal of ​“providing the revenue certainty that hydrogen producers require to attract private sector investment.”

Just what form that demand-side initiative might take is still unclear, however. EFIF recently joined a consortium formed by DOE to ​“design robust demand-side support measures that will facilitate purchases of clean hydrogen produced by H2Hub-affiliated projects,” but the design of those measures is expected to take six to nine months.

Nor is it clear how U.S. government policies might be able to create the same kinds of demand-side regulatory mandates for dirty-hydrogen users to switch to lower-carbon alternatives that exist in Europe.

Cihang Yuan, a senior program officer at the environmental nonprofit World Wildlife Fund, highlighted the importance of creating new structures to support clean-hydrogen demand in the sectors that need it most. Yuan leads WWF’s clean-hydrogen work for the Renewable Thermal Collaborative, a coalition of industrial companies seeking to decarbonize their processes.

Clean hydrogen is one such option, but ​“there is a concern in the industry that we need more demand-side support,” she said. ​“A lot of the focus and discussion has been on the production side. But now that we’ve announced the hubs and have this substantial support for production, it’s important to have the same level of attention and nuanced support for the demand side.”

Canary Media’s Maria Gallucci contributed reporting for this article. 

Verdagy manufactures an advanced AWE electrolyzer system that has superior performance to almost any system in the market — high current densities and the largest membranes leading to higher hydrogen production, high efficiencies leading to lower LCOH, and wide dynamic range and fast turndowns to seamlessly integrate with renewables. In addition to its Silicon Valley factory, Verdagy operates its R&D and highly automated commercial pilot plants in Moss Landing, California, where it continues to advance its cutting-edge technology.