US green hydrogen hub will put long-haul energy storage to the test

Canary Media’s Down to the Wire column tackles the more complicated challenges of decarbonizing our energy systems. Canary thanks CPower for its support of the column.

As the chief operating officer of Advanced Clean Energy Storage Delta, Michael Ducker gets a lot of questions about how the developer’s first-of-its-kind green hydrogen project, now being built in Utah, will be economically feasible — and he has some points he’d like to clarify.

One question he hears a lot: How can the project’s backers justify sinking billions of dollars in public- and private-sector investment into making hydrogen from renewable electricity when it will cost much more than making hydrogen from fossil gas on a per-kilogram basis?

How can they rationalize burning that hydrogen to generate electricity when the amount of electricity created will be less than half the amount used to make the hydrogen in the first place?

And why would a project use hydrogen for energy storage instead of lithium-ion batteries, which are much cheaper and more efficient, at least for storing electricity for hours at a time?

But the ACES Delta project isn’t designed to store energy for hours or even days, said Ducker, who is also senior vice president of hydrogen infrastructure for Mitsubishi Power Americas, one of two main ACES Delta project partners. Instead, it’s meant to store energy for months — soaking up solar and wind power that will flood an increasingly clean-powered Western U.S. grid during the spring and fall and saving it to make electricity that can cover the inevitable shortfalls in renewable power supply during summer heat waves and droughts, and during cloudy or windless winter months. It’s intended to ultimately be an integral part of a 100 percent clean electricity system.

When you look at green hydrogen from this perspective as a ​“seasonal energy storage” resource, concerns about it being too expensive or inefficient become less relevant, he said. 

“Everybody in the industry talks about dollars per kilogram for hydrogen,” Ducker said in an interview this week. But ​“that’s completely irrelevant when it comes to using green hydrogen for seasonal storage.”

This kind of project may not pencil out economically in today’s Western U.S. energy markets, he acknowledged. But Ducker and Aces Delta believe that long-duration energy storage will become indispensable over the next two decades.

“You cannot achieve a low-cost, high-reliability and zero-carbon grid without hydrogen playing a fundamental role,” he said. ACES Delta’s primary customer for this hydrogen-based energy storage capacity, Utah-based Intermountain Power Agency, ​“is taking the first steps in showing that value.” IPA is a municipal and cooperative utility consortium whose majority owner, the massive Los Angeles Department of Water and Power, has pledged to reach zero-carbon power by 2045.

If the ACES Delta project succeeds with its ambitious vision of seasonal energy storage, it would then be well positioned to jump-start a broader hydrogen economy in the Intermountain West by providing green hydrogen for a host of other uses, Ducker said. But those yet-to-be-developed use cases are far more dependent on reducing the price of green hydrogen to compete with hydrogen made from fossil gas.

As the first of a number of would-be major green hydrogen production and storage sites in the U.S. to receive significant financial commitments, ACES Delta is being watched closely by energy industry players and policymakers.

This project’s investors are betting on the success of a clean-energy future that has yet to emerge. Many energy experts fear that this future won’t be possible without building infrastructure like the ACES Delta project well ahead of the need for it — one of the many chicken-and-egg problems that need to be solved to decarbonize the country’s electricity mix.

A big bet on an unproven use case for hydrogen

Situated in the town of Delta in central Utah, the ACES hydrogen hub has been in the works since 2019. But it got an important vote of confidence from the U.S. Department of Energy last month in the form of a $504 million loan guarantee from DOE’s Loan Programs Office — the first commitment made by this pivotal federal clean-energy backer to support a new kind of clean energy project in almost a decade.

The project has also secured equity investments organized by Haddington Ventures, which has announced $650 million in commitments from Alberta Investment Management Corporation, GIC, Manulife Financial Corporation and Ontario Teachers’ Pension Plan Board. This equity syndication could increase to $1.5 billion over time. (ACES Delta has also lost one potential investor, oil company Chevron, which announced earlier this month that it was pulling out of a 2021 agreement to acquire an equity stake in the project.)

Mitsubishi Power is in charge of procuring the 220 megawatts of electrolyzers that will use renewable electricity to produce up to 100 metric tons of hydrogen per day. It’s also working with ACES Delta’s other project partner, Magnum Development, to expand gigantic underground salt caverns in the area that Magnum owns so they can store the hydrogen produced by those electrolyzers. By hollowing out the salt domes with water, the partners plan to create two underground repositories, each large enough to store 150 gigawatt-hours of energy.

That hydrogen will be the source of fuel for IPP Renewed, a project by the Intermountain Power Agency to retrofit an existing coal plant with turbines that will start producing up to 840 megawatts of power using a blend of 30 percent hydrogen and 70 percent fossil gas in 2025. Over the next two decades, Mitsubishi Power and IPA will gradually retrofit the plant so it can run on 100 percent hydrogen by 2045 — the deadline the Los Angeles Dept. of Water and Power has set for reaching zero-carbon electricity. The IPP Renewed project is backed by $798 million in bonds.

Much bigger green hydrogen projects are on the drawing board in Europe, the Middle East, Asia and Australia. But according to ACES Delta, ​“this is the largest green hydrogen project in the world to enter construction,” said Jason Rowell, associate vice president and director of new energy solutions with Black & Veatch, the engineering firm picked to work on the ACES hydrogen hub. Construction is on track to begin this summer, and IPP Renewed is set to begin operations in 2025.

Green hydrogen is being targeted for use in industries ranging from shipping to steelmaking. A major challenge is bringing the cost of making hydrogen from clean electricity down from about $5 or $6 per kilogram today to between $1 and $2, a price point at which it can compete with hydrogen made from fossil gas.

“We’ve heard from multiple end clients of ours and technology suppliers just how hard it is to get a project-financeable deal for something novel like [green] hydrogen at this scale,” Rowell said. ​“We need to do projects like this to get the costs down.”

That’s why DOE’s Loan Programs Office has been exploring making loan guarantees to a number of other hydrogen projects as well as ACES Delta. At an event last month unveiling the $504 million loan guarantee, the office’s head, Jigar Shah, said the goal is to ​“commercialize hydrogen and long-duration storage by enabling these technologies to cross the bridge to bankability.”

How seasonal energy storage differs from other grid needs

Hydrogen for long-duration energy storage needs this kind of ​“bridge to bankability” because it’s never been done before. The very concept of ​“seasonal energy storage” has emerged from the unique needs of a renewable-powered grid.

“Any 100 percent [clean energy] plan needs something to cover your ass during a few hours a year, or a few hours every few years,” said Eric Gimon, senior fellow at think tank Energy Innovation.

A grid that runs predominantly on solar and wind power requires a source of power that can step in during days or weeks of low wind and sun, known in the industry by the German term ​“Dunkelflaute,” or ​“dark doldrums,” used to describe conditions that are common in colder parts of Europe but can happen in any geography.

The value of energy resources that can step up during these periods is far greater than the prices they can typically demand in today’s grid power markets, Gimon said. That makes the economics of using hydrogen for seasonal storage very different than the economics of using hydrogen for everyday grid needs.

The Intermountain Power Project, the coal plant in Utah set to be converted to be powered by turbines using hydrogen, provides about 16 percent of the power used by the Los Angeles Dept. of Water and Power today, Gimon noted. But ​“you would not want to get 16 percent of your power from green hydrogen,” he said.

That’s because the ​“round-trip efficiency” of converting electricity to hydrogen, then burning that hydrogen to generate electricity, is only about 33 percent, he said. In other words, ​“for every megawatt-hour you’re outputting, you’re consuming three” — a major waste of resources.

For that reason, energy experts have little confidence that hydrogen could replace fossil gas for running power plants throughout the year. The round-trip efficiency losses are just too great. In California’s energy markets, ​“if you’re buying power at $20 a megawatt-hour and you lose two-thirds of it, you need to sell it at $60” to make a profit, Gimon said, and prices rarely rise that high.

Nor is hydrogen a suitable replacement fuel for the ​“peaker” plants that power up to cover hour-by-hour surges in grid electricity demand. Lithium-ion batteries, which have round-trip efficiencies in the high 80 percent range and above, are far more efficient for that purpose.

These efficiency equations are flipped, however, when it comes to storing excess renewables in the spring and discharging that power in the summer. Building enough dedicated lithium-ion battery capacity just for those rare but vital services would be enormously expensive. It would also be a waste of batteries that are far more valuable for hour-to-hour grid balancing.

But hydrogen ​“as an insurance option” can work for this seasonal use case, Gimon said. Wholesale power prices can spike to more than $1,000 per megawatt-hour when high levels of demand put the grid at risk of rolling blackouts, as is increasingly happening across the U.S. West, he said. ​“That’s where it starts to make sense,” both as an insurance policy for utilities and their customers and as a cost-effective investment of taxpayer dollars for policymakers looking at ways to move power grids toward 100 percent carbon-free energy.

Mitsubishi Power has analyzed the costs and benefits of tapping the seasonal-storage value of hydrogen. The following graphic shows projections for energy costs in California through 2050, with the base case in the left bar chart representing a 100 percent clean power system using renewables and lithium-ion batteries alone, and the hydrogen case in the right bar chart representing a system that also includes hydrogen-powered long-duration storage. With hydrogen storage, the cost of energy is projected to be 16 percent lower by 2050 compared to the scenario without it.

“We’re not saying that hydrogen replaces batteries or zero-carbon forms of energy,” Ducker said. But for covering those rare hours of the year when wind and solar can’t keep up with the demand for electricity, using hydrogen is much cheaper than alternatives, even with its efficiency and cost disadvantages.

Today, energy markets aren’t designed to reward the kinds of investments that will be needed decades into the future, he noted. The Los Angeles Dept. of Water and Power took the plunge and decided to invest in the ACES hub project based on a study from DOE’s National Renewable Energy Laboratory that found that green hydrogen was the most cost-effective pathway for the region to fully decarbonize its grid by 2035.

“Several other utilities we’re working with across the U.S. have the ability to have that longer-term foresight, to agree it’s not just about the three- or four-year-ahead curve, but how to hit these targets over the next one to two decades,” Ducker said. But regional grid operators for about two-thirds of the U.S. ​“don’t yet take this long-term view” or formally value resources in terms of their role in reducing carbon emissions, he said.

The merits of seasonal storage versus ​“clean firm power” 

To be sure, hydrogen will face competition to be this last-resort source of electricity generation capacity, said Eric Hittinger, department chair for public policy at the Rochester Institute of Technology. Other contenders include ​“clean firm generation” sources such as geothermal power, fossil gas plants with carbon capture and storage, and nuclear power, all of which are ​“not cheap to build,” but still potentially worth it to ​“meet that last 10 percent of zero-carbon electricity” in a 100 percent clean grid scenario, he said.

A study published last year by MIT researchers and Princeton energy professor Jesse Jenkins compared the costs of a range of long-duration energy-storage technologies to the costs of clean firm generation resources. The results highlight the complexity of trying to forecast future values for technologies meant to solve a problem that doesn’t yet exist: the need to cover gaps in wind and solar production.

“Energy markets are designed right now to currently price energy today — and the value is really low because we don’t have one of these high-wind-and-solar-electricity grids today that would make it increasingly valuable,” Hittinger said.

But in a future in which renewable energy is being generated in excess of demand in certain seasons, technologies that can store that energy may end up providing greater value compared to clean firm technologies that don’t tap into that excess wind and solar power, he said.

“The prices of that renewable energy will be effectively zero” when it’s not needed, Hittinger said. ​“That’s already happening” in places like Texas with its surfeit of wind power and California with its surfeit of solar power, where an increasing amount of renewable energy is being curtailed, meaning market operators are forced to temporarily shut down wind and solar farms because the power produced has nowhere to go. This chart shows the increase in solar curtailments in recent years by California grid operator CAISO.

Mitsubishi Power’s analysis of the economics of the ACES Delta hydrogen hub project found that curtailment will likely continue to increase in coming years. At the same time, California and other parts of the U.S. West are falling short of grid power in summer months, Ducker said — so short at certain times that state grid operator CAISO has been forced to institute emergency measures including rolling blackouts.

Still, securing enough renewable energy to power the ACES Delta hydrogen hub throughout the whole year won’t necessarily be easy; the project has committed to make 100 percent of its hydrogen from zero-carbon electricity. Its success will depend on how quickly renewable energy infrastructure can be built across the U.S. West, and on whether or not new transmission lines are completed, including a major one planned to bring wind power from Wyoming through Delta, Utah to California.

The IPP Renewed project will also depend on Mitsubishi successfully adapting the turbines it’s supplying to run on fuel blends with higher and higher proportions of hydrogen. The company recently proved that its latest generation of turbines can run on a blend of 20 percent hydrogen and 80 percent fossil gas, and it has a pathway to making the switch to 100 percent hydrogen over the coming two decades, Ducker said. But environmental groups worry that utilities may end up delaying the switch from fossil gas to hydrogen for projects like these if the economics of making that switch prove less favorable, which could lock in continued gas use.

Matching the scale of clean power with the capacity of salt-cavern storage

The growth of solar and wind power across the U.S. West will also be important for ensuring that the project can use its electrolyzers to make hydrogen as often as possible, Gimon said. After the price of electricity, the biggest factor for cost-effective green hydrogen production is ​“capacity utilization,” or how many hours each month electrolyzers can operate to pay off the cost of building and deploying them.

For green hydrogen projects to get anywhere close to the magic $1–$2 per kilogram cost needed to compete with fossil-fuel-derived hydrogen in most applications, ​“you want to run that equipment 80 percent of the time” or even more, Gimon said. If the rate of capacity utilization falls too low, the price of the hydrogen goes up, he said.

But having an enormous underground reservoir gives the ACES Delta hub much lower storage costs than it would have if it were keeping its hydrogen aboveground in pressurized tanks, he said. It also allows the project to start out with a relatively small amount of electrolyzer capacity and stockpile hydrogen for future years when the power plant will need it.

“You start out filling up the cavern for what [Los Angeles] wants — and right now it doesn’t need that much,” Gimon said. ​“As you understand more, you slowly increase your electrolyzer capacity.”

The salt domes beneath Delta, Utah are massive, similar in scale to those now used to store oil and gas in the Gulf Coast region. They could eventually hold enough hydrogen to meet the grid needs of utilities well beyond the Los Angeles Dept. of Water and Power. As DOE’s Jigar Shah mentioned during his announcement of the project’s loan guarantee, NREL research indicates that the ACES Delta hub’s 150-gigawatt-hour storage capacity could be enough to supply seasonal storage at a scale that would allow utilities across the Western U.S. to decarbonize by 2035.

This chart from Mitsubishi Power shows the storage and electrolyzer capacity utilization rate expected from the ACES Delta project, which the company believes could support energy storage across the Western U.S.

Those capacity-utilization figures are well below the 80 percent range that Gimon identified as a tipping point for bringing down the cost of green hydrogen. But Ducker reiterated his view that cost per kilogram isn’t the proper metric by which to measure the value of hydrogen as seasonal storage.

“The question is, how do we get to the lowest systemwide costs for zero-carbon?” Ducker said. Adding hydrogen to the mix would save money in terms of not needing to build as much renewable energy and battery infrastructure, or salvaged value from wind and solar that would otherwise need to be curtailed, he said. It would also help ensure that grid operators and utilities aren’t forced to keep burning fossil fuels to provide the reliability needed as the grid approaches ever-higher penetrations of renewables — something that California is already coping with today.

What else can you do with green hydrogen? 

But the cost of hydrogen from the ACES Delta hub project will be an important factor in future years if it’s to be used for applications beyond seasonal energy storage. ​“You could start creating native industries around that region that make fertilizer, or green steel, or whatever you want to make with green hydrogen,” Gimon said.

That’s a fundamental premise behind the concept of ​“hydrogen hubs,” or sites that combine low-carbon or green hydrogen production with a variety of uses.

“The term that gets used quite often is ​‘sector coupling,’” Black & Veatch’s Rowell said. One significant use for the hydrogen produced could be the production of ammonia, a key ingredient in fertilizer and a potential fuel for shipping and other transport. ​“We’ve seen ammonia prices go astronomically high over the past year,” Rowell said. The skyrocketing costs have been driven by price spikes in the fossil gas that’s used to make almost all ammonia today. ​“Green ammonia is going to be very stable” in terms of cost compared to ammonia made from fossil fuels, he said.

Ducker said that ACES Delta is in discussions with ​“other entities about how to expand this site over time” to support different use cases, though he wouldn’t provide any details. ​“With scale, you get costs down — and with costs down, you can attract new industries, new verticals.”

Hittinger said it’s currently ​“hard to say what that flexibility is worth.” But hydrogen does have a much broader range of uses than other forms of seasonal energy storage like pumped hydropower, compressed air energy storage, novel battery chemistries or thermal energy storage systems — and ​“that flexibility means we don’t have to decide today” what those uses might be.

This uncertainty makes it difficult to pin down an accurate economic valuation of the ACES Delta project, Hittinger said, or to evaluate the broader prospect for green hydrogen to help decarbonize the power grid and other industries. In that light, ​“other long-duration storage developers will be looking at this” to see whether the deal between ACES Delta, Intermountain Power Agency and the Los Angeles Dept. of Water and Power ends up working out for everyone involved.

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This column is sponsored by CPower. CPower is a leading national energy solutions provider guiding customers toward a clean and dependable energy future. We maximize the value of our customers’ DERs by facilitating and optimizing participation in demand-side management programs, forming virtual power plants that are good for the grid and great for the community. CPower works with over 11,000 sites across North America to provide superior economics while delivering the highest-rated customer experience in the industry.