A cadre of start-ups are building batteries that can store renewable energy in natural materials such as sand, salt and rock.
(Illustration by Emily Sabens/The Washington Post; iStock)
TAMPERE, Finland — When Russia halted gas and oil exports to Europe following its invasion of Ukraine, hundreds of millions of citizens agonized over the prospect of a winter without enough heating and a summer without enough air conditioning.
But the Kremlin’s wartime strategy to shut the taps on its fossil fuels has coincided with, and also catalyzed, a critical sector for the clean energy transition — batteries made from inexpensive and abundant natural materials that store heat.
The use of sand, salt, heat, air and other elements as energy banks dates back centuries. The walls of ancient Egyptian homes captured solar heat during the day and released it during cool desert nights. Indigenous peoples across the Americas valued adobe — a composite of earth, water, and other organic materials like straw or dung — as a preferred construction material for its ability to do the same.
For modern civilizations whose industrial development has been powered by the combustion of fossil fuels, these materials offer a revolutionary premise: “Nothing is burned,” said Tommi Eronen, chief executive of Polar Night Energy, a Finnish start-up running the world’s first commercial-scale sand battery.
Natural batteries are meant to enable countries to take advantage of prodigious supplies coming from wind turbines and solar panels, when the sun isn’t shining and the wind isn’t blowing. The price of renewables remains below the cost for fossil fuels —especially after a Russian fuel pullback drove prices across Europe to record highs — but the green energy revolution still faces a hugeobstacle: a lack of long-term, cost-efficient renewable storage.
At Polar Night Energy’s facilities in the city of Tampere and the nearby town of Kankaanpää, hulking steel vats hold heaps of sand, heated to around 1,000 degrees Fahrenheit. That stored energyhelps to smooth out power grid spikes and back up district heating networks, keeping homes, offices, saunas and swimming pools warm. The heat keeps flowing, even in remote areas, even as Russian fossil fuel supplies dwindle.
“Sand has almost no limits,” said Ville Kivioja, Polar Night Energy’s lead scientist, speaking over the whirring sound of the substance circulating. “And it’s everywhere.”
A Polar Night Energy sand battery. (Martti Tikka)
How natural batteries work
The sensors and valves that monitor the sand battery’s performance are relatively high-tech, said Kivioja, but, by design, the battery itself is simple.
The sand is trucked in from anywhere nearby — a demolished building site or sand dunes, for example — and costs less than a euro per ton. It is dumped into a giant vat, or “battery,” which is consistently kept hot, or “charged.”
The renewable energy from solar panels and wind turbines is converted into heat by a resistance heater, which also heats the air that swirls through the sand. A fan circulates the flow of heat continuously, until it’s ready to use. Like a boulder in the sun, the sand remains hot even after sundown — except unlike the boulder, the sand never gets cold because it’s insulated by the enormous vat. Even when the battery level is low, the temperature remains above 200 degrees Fahrenheit; when it is full, it can surpass 1,000 degrees.
The sand can hold onto the power for weeks or months at a time — a clear advantage over the lithium ion battery, the giant of today’s battery market, which usually can hold energy for only a number of hours.
Polar Night Energy prefers to use sand or sand-like materials that are not suitable for construction industry. This enables the usage of materials that are locally and commonly available or even considered as waste. (Polar Night Energy)
A natural battery rush
Unlike fossil fuels, which can be easily transported and stored, solar and wind supplies fluctuate. Most of the renewable power that isn’t used immediately is lost.
The solution is storage innovation, many industry experts agree. In addition to their limited capacity, lithium ionbatteries, which are used to power everything from mobile phones to laptops to electric vehicles, tend to fade with every recharge and are highly flammable, resulting in a growing number of deadly fires across the world.
The extraction of cobalt, the lucrative raw material used in lithium ion batteries, also relies on child labor. U.N. agencies have estimated that 40,000 boys and girls work in the industry, with few safety measures and paltry compensation.
These serious environmental and human rights challenges pose a problem for the electric vehicle industry, which requires a huge supply of critical minerals.
So investors are now pouring money into even bigger battery ventures. More than $900 million has been invested in clean storage technologies since 2021, up from $360 million the year before, according to the Long Duration Energy Storage Council, an organization launched after that year’s U.N. climate conference to oversee the world’s decarbonization. The group predicts that by 2040, large-scale,renewable energy storage investments could reach $3 trillion.
That includes efforts to turn natural materials into batteries.Once-obscure start-ups, experimenting with once-humble commodities, are suddenly receiving millions in government and private funding. There’s the multi-megawatt CO2 battery in Sardinia, a rock-based storage system in Tuscany, and a Swiss company that’s moving massive bricks along a 230-foot tall building to store and generate renewable energy. One Danish battery start-up, which stores energy from molten salt, is sketching out plans to deploy power plants in decommissioned coal mines across three continents.
“In some ways, these are some of the oldest technologies we have,” said Kurt Engelbrecht, an associate professor who specializes in energy storage at the Danish Tech University.
He and his colleagues have long been advocating for national decarbonization programs to integrate simple, natural based storage solutions,he said, but clean batteries only began receiving real market attention as a result of energy crises of recent years.
The war in Ukraine and the subsequent political crisis over Russian oil and gas exports, was the final “tipping point,” Engelbrecht said.
The geopolitical benefits of natural batteries
Natural batteries will help renewables eclipse fossil fuels and free countries from geopolitical challenges, such as Russia’s Ukraine invasion, said Claudio Spadacini, founder of Italian company Energy Dome. The company has been considering selling a version of its CO2-based battery to clients in the United States.
“Renewables are democratic,” he said. “The sun shines everywhere and the wind blows everywhere, and if we can exploit those sources locally, using components that already exist, that will be the missing piece of the puzzle.”
But in order to succeed, natural batteries will need to provide the same kind of steady power as fossil fuels, at scale.Whether that can be achieved remains to be seen, say energy experts.
And the industry may be subject to the same pitfalls that loom over the renewables energy sector at large: Projects will need to be constructed from scratch, and they might only be adopted in developed countries that can afford such experimentation.
Lovschall-Jensen, the CEO of a Danish molten salt-based storage start-up called Hyme, says the challenge will be maintaining the same standards to which the modern world has become accustomed: receiving power, on demand, with the flip of a switch. He believes that natural batteries, though still in their infancy, can serve that goal.
“As a society that’s going away from fossil fuels, we still need something that’s just as flexible,” he said. “There’s really no other option.”
Written by: Jonathan Lewis and Anna Menke View the original article here
Low-emissions hydrogen is a critical component of the climate change solution set, and it is likely to play a significant role in affordably achieving full, economy-wide decarbonization by midcentury. Electrification will achieve much of the decarbonization needed, but more than 80% of final energy use in the U.S. comes from fuels. Many existing fuel uses can be electrified, but electrifying some hard-to-abate sectors of the economy (such as long-haul heavy-duty trucking, marine shipping, and ironmaking) may be either commercially impossible or prohibitively expensive. For these sectors, we will need zero-carbon fuels, namely hydrogen and ammonia, to reach full decarbonization. Accordingly, the International Energy Agency (IEA) projects that the world’s demand for hydrogen could increase by almost 500% between 2020 and 2050.
To catapult the United States on a path towards commercial scale clean hydrogen production, the 2021 Infrastructure Investment and Jobs Act (IIJA) allocated $8 billion for the Department of Energy (DOE) to fund at least four Regional Clean Hydrogen Hubs — or H2 Hubs — across the country. The program is designed to demonstrate viability of new production and end-use technologies for clean hydrogen, and to drastically bring the cost of production down.
A clean hydrogen hub is a co-located network of infrastructure needed to produce, transport, store, and use clean hydrogen in a functional regional market. The program intends to demonstrate localized production and end use of hydrogen and to create a connected synergistic hydrogen economy across the United States.
In parallel to DOE’s H2 Hubs program, DOE and the Department of Transportation (DOT) are pursuing several additional measures to promote the deployment of hydrogen-fueled trucks and ammonia-powered marine vessels, including the IIJA’s National Alternative Fuel Corridors Program — a piece of the $2.5 billion Charging and Fueling Infrastructure competitive grant program that is designed to support the build-out of clean charging and fueling infrastructure projects along designated alternative fuel corridors of the National Highway System.
Clean transportation corridors include routes for heavy-duty trucks that run on hydrogen to transport their freight across multiple states, provinces, or even countries, as well as transoceanic shipping routes for vessels that run on ammonia. In the future, clean corridors will also include airline routes serviced by aircraft that are powered by hydrogen or other zero-carbon fuels. Clean transportation corridors will be necessary to turn H2 Hubs from islands into a network, allowing hydrogen and other resources to move between hubs and simultaneously creating a steady demand base for hydrogen to fuel the transportation corridors themselves.
Moving from competition to connection between H2 Hubs
CATF has previously written about the elements that individual hubs should prioritize as they develop their proposals to DOE, including low-carbon production pathways, hard-to-decarbonize end uses, the creation of community and local environmental benefits, and long-term economic viability.
On April 7, 2023, final applications were submitted from hub developers across the country hopeful to receive funding from the Department of Energy. The application process for the DOE Regional Clean Hydrogen Hubs program is long and applicants have recently entered a new phase – the waiting period between application submission and award negotiations and selections. Until this point in the process, the focus and feel between hub hopefuls has been competitive with more than 20 known hub efforts competing for $8B in funding to be spread amongst the 4 to 10 hubs that will be selected by DOE. As award selections and negotiations evolve over the spring, summer, and into the fall, we expect to see more tangible production proposals, off-taker agreements, robust community engagement efforts, and greater collaboration and coordination between the various hub efforts.
In addition to getting specific within each hub proposal, this phase of the program creates an opportunity for hub developers and the Department of Energy to start thinking collaboratively. Proactive planning to connect hubs can strengthen individual proposals and improve the likelihood of long-term success for the collective H2 Hubs program. As the Department of Energy’s Clean Hydrogen Liftoff report points out, the development of ‘midstream infrastructure’ will be crucial to getting hydrogen to commercial scale. For the H2 Hubs program, this midstream infrastructure will include hydrogen storage, carbon storage, and transportation infrastructure. The ability to move hydrogen efficiently and safely between hubs — while minimizing hydrogen leaks throughout the process — will be an essential part of the H2 Hubs program. There is the potential to create a national network that simultaneously allows for distribution and hydrogen refueling across the country while bolstering demand for hydrogen and creating benefits for communities.
The importance of linking clean transportation corridors and H2 Hubs
Clean transportation corridors have the potential to bolster the economic viability of H2 Hubs and create benefits to communities. To date, Congress and the U.S. DOE have focused primarily on supply-side policies for hydrogen; including the Regional Clean Hydrogen Hubs Program and the Hydrogen Production Tax credit (45V). Recently, focus has begun to shift to demand-side measures that could help give certainty to hub developers that off takers will be there for the hydrogen they produce. DOE and DOT’s investments in and development of clean, hydrogen-fueled transportation corridors will aid in demand-side certainty for H2 Hubs in two ways:
Clean transportation corridors that support trucks and marine vessels that run on hydrogen or hydrogen-based fuels will broaden the market for low-carbon hydrogen by increasing demand beyond the industrial off takers that are typically located next door to hydrogen production sites.
The corridors will also expand the geographic reach of H2 Hubs by extending demand for decarbonized hydrogen along spokes — i.e., highways and/or marine shipping routes — that connect each hub region to other cities and ports.
Additionally, clean transportation corridors have an important role not only in curbing harmful CO2 emissions but also in curbing conventional air pollutants from diesel powered trucking which disproportionately affect environmental justice communities across the country. As H2 Hubs evaluate the benefits they may be able to create for communities near and far, they should consider the transportation routes stemming from their hubs that could transition to be hydrogen-fueled clean transportation corridors and should begin benchmarking the public health benefits that may accrue to communities as a result.
The first awardees of the DOE and DOT clean transportation corridors grant program were announced in February and include several awardees focused on developing hydrogen-fueled clean transportation corridors:
CALSTART: East Coast Commercial ZEV Corridor along the I-95 freight corridor from Georgia to New Jersey.
Cummins Inc.: MD-HD ZEV Infrastructure Planning with Focus on I-80 Midwest Corridor serving Indiana, Illinois, and Ohio.
GTI Energy: Houston to Los Angeles (H2LA)–I-10 Hydrogen Corridor Project.
Utah State University: Wasatch Front Multi-Modal Corridor Electrification Plan for the Greater Salt Lake City Region.
CATF sees a key opportunity for H2 Hubs and clean corridors grant recipients to coordinate to develop an interconnected hydrogen network across the United States.
Imagining hubs connected via clean transportation corridors
Given that around half of the hydrogen production in the United States currently takes place in the Gulf Coast, let’s assume the example of a hydrogen hub depicted in the graphic above is in the Houston region. If a Houston-based hub were to be selected, there would be at least three and at most nine other hydrogen hubs under development in the United States per the requirements of IIJA’s Regional Clean Hydrogen Hub provision. Meaning, the hypothetical hub in Houston isn’t the only one of its kind, and a hydrogen-powered truck that fuels up in Houston isn’t limited to conducting only local deliveries. There are other places it could carry its freight to, if those places — and the routes along the way — also have hydrogen fueling capacity.
If a hub in Chicago and the Upper Midwest/Great Lakes region was also selected, the ability to move goods between Houston and Chicago and points in between would improve the use-case for hydrogen trucks purchased in those regions — which in turn would benefit hydrogen truck manufacturers, producers of low-carbon hydrogen, and, most pertinently, air quality and the climate.
The success of this Houston-Chicago clean hydrogen corridor could be replicated with corridors that connect those regions to other potential hosts of federally backed regional clean hydrogen hubs. Once there are hydrogen production facilities in places like Los Angeles, New Orleans, and New York, along with hydrogen fueling stations along the interstate highways that connect them, the viability of hydrogen-fueled trucks would improve dramatically, the market for low-emissions hydrogen would increase, and both sectors would benefit from growing economies of scale.
The success of this Houston-Chicago clean hydrogen corridor could be replicated with corridors that connect those regions to other potential hosts of federally backed regional clean hydrogen hubs. Once there are hydrogen production facilities in places like Los Angeles, New Orleans, and New York, along with hydrogen fueling stations along the interstate highways that connect them, the viability of hydrogen-fueled trucks would improve dramatically, the market for low-emissions hydrogen would increase, and both sectors would benefit from growing economies of scale.
Concluding: How DOE and hub developers can support the development of clean transportation corridors
Building synergistic linkages between H2 Hubs and clean trucking and shipping corridors requires multi-market investments by fuel providers, fleet owners, and other market participants; support and coordination from federal and state agencies; and constructive input and oversight from communities, NGOs, and universities.
As discussed above, DOE, DOT, and other U.S. government agencies are working on multiple fronts to implement key provisions in the IIJA and the Inflation Reduction Act that will support the deployment of clean energy production and utilization technologies including hydrogen and zero emissions vehicles. More can be done, however, to ensure that the H2 Hubs and clean corridors programs are well coordinated. The seven grant recipients of DOE and DOT’s program “to accelerate the creation zero-emission vehicle corridors” cover highway systems across the country and meanwhile, nearly every state in the U.S. is represented in the hub projects proposed to DOE’s H2 Hubs program. The extent to which the seven funded corridor efforts match up geographically with regional hydrogen hub efforts is not yet known, because the Regional Clean Hydrogen Hubs program funding recipients will not be announced until later this year.
may proceed irrespective of DOE funding decisions. Accordingly, CATF is connecting with DOE, hydrogen hub developers, trucking companies, and others to spotlight the opportunities for constructively linking clean corridor development and H2 Hub development. We’re encouraging H2 Hub project developers to look for ways to integrate clean corridor plans into their strategy, in part by involving entities like Cummins, GTI Energy, CALSTART, and Utah State University that received initial clean corridor grants from DOE and plan to support hydrogen refueling infrastructure as part of their projects.
Given the likely importance of hydrogen to the decarbonization of long-haul heavy-duty trucks, DOE and DOT should account for H2 Hub development when determining when and how to expand the clean corridors program, and the agencies should prioritize the development of hydrogen fueling infrastructure along routes that span between H2 Hub regions. Additionally, H2 Hub applicants and DOE should consider how clean corridors can be leveraged to improve demand-side certainty and to create meaningful benefits for communities. As selections are announced later this fall, CATF looks forward to collaborating with clean corridor grant recipients, H2 Hub awardees, and other stakeholders to support the development of a connected clean hydrogen ecosystem across the United States.
By Joseph Webster and William Tobin View the original article here
Long-haul trucking is a highly promising use case for the US hydrogen industry, and California and Texas are two large potential markets for pioneering hydrogen-fueled trucking. Both states have excellent green hydrogen potential and are taking initial steps to become hydrogen trucking hubs. When it comes to decarbonizing heavy-duty transportation, hydrogen is here for the long-haul.
Cleaning up hydrogen
Today, the vast majority of hydrogen is produced from reforming the methane in coal or natural gas in a process that produces ten times more carbon dioxide than hydrogen by mass. It is principally used for refining heavy sour oil and producing ammonia for fertilizer.
The most promising pathways to create zero-carbon clean hydrogen at scale are through renewables-produced green hydrogen or nuclear-powered pink hydrogen, both of which use zero-carbon electricity to separate hydrogen and oxygen via electrolysis. There is also blue hydrogen, which comes from natural gas in a process paired with carbon capture. Blue hydrogen’s role in decarbonization, however, is contingent on the mass buildout of carbon transportation and storage infrastructure.
If deployed judiciously, clean hydrogen can have a meaningful impact on lowering emissions in hard-to-electrify sectors, which require a chemical feedstock, long-duration energy storage, or extreme heat.
Long-haul trucking is a viable clean hydrogen offtaker
For most forms of transportation, growing economies of scale have given batteries an edge over hydrogen fuel cells. However, long-haul trucking—which accounts for 7 percent of transportation emissions—may be too high a fence for batteries to climb.
As a vehicle becomes heavier, its battery must expand proportionately in volume to provide the requisite power. Electric freight tractors use battery packs that are significantly heavier than the weight of diesel a truck typically carries, which decreases range and payload capacity while requiring more frequent charging. This is meaningful in the freight industry, where time is precious, and downtime can come at a cost of over $50 per hour before accounting for costs of charging. An electric long-haul truck takes thirty minutes to charge to only 70 percent capacity even with megawatt charging. In comparison, hydrogen re-fueling can be done quickly. Refueling a hydrogen truck takes ten minutes.
Hydrogen fuel cell trucks are therefore likely to edge out batteries for trips surpassing 180 miles and payloads above 24,000 pounds, according to an industry study.
The US Department of Energy estimates that total cost of ownership for hydrogen fuel cell long-haul vehicles will become affordable by 2030 thanks to new production tax credits for clean hydrogen. Furthermore, the department cites evidence that the long-haul trucking sector is willing to pay a premium for clean hydrogen. This outcome, however, is contingent on a buildout of refueling infrastructure along freight corridors. To boost demand, infrastructure could be built along freight lines that support high volumes of freight, such as near seaports. This can help medium-sized refueling stations reach their breakeven utilization rate. To do so, industry and policymakers must overcome a chicken-and-egg problem. The development of refueling infrastructure is critical to enable hydrogen-powered long-haul trucks, and—conversely—hydrogen refueling stations will rely on long-haul trucking for their income, as hydrogen uptake in transportation is likely to be confined to this sector.
California and Texas: Unlikely hydrogen trucking partners
California and Texas are important players in both green hydrogen and long-haul trucking.
Not only do the two states have the largest populations and economies in the country, but they also have outstanding green hydrogen potential.
Both California and Texas have excellent renewable resources, including solar and wind. The two states have deployed nearly 74 gigawatts of solar and wind capacity with another 36 GW in development.
Texas and California are the nation’s largest and second-largest renewables generators. As more renewable electricity production grows in these states, so will green hydrogen capacity—although there will be tensions between providing renewables for power generation or hydrogen.
Long-haul trucking is a natural use case for green hydrogen in both states. Texas and California are the country’s largest users of diesel for the transportation sector, consuming 633,000 barrels per day in 2021, or about 21 percent of total US diesel demand. Both states rely heavily on trucking to transport cargo from ports along the coast of California and Texas to destinations further inland. Indeed, Los Angeles, Long Beach, and Houston are the country’s first, second, and fifth-largest container ports by volume, respectively.
There is already evidence that Texas and California’s long-haul trucking sectors could see synergies between ports and green hydrogen production. California provides fiscal support for zero-emissions vehicles, plans to end the sale of fossil fuel-powered medium- and heavy-duty trucks by 2036, and continues to develop hydrogen refueling infrastructure. Tellingly, Hyundai Motor will soon operate thirty fuel cell electric trucks in California; Hyundai states this deployment will mark the largest commercial deployment of fuel cell electric trucks in the United States in the super-large vehicle class. In North Texas, Air Products and AES are teaming up to construct the country’s largest green hydrogen facility to service the trucking industry.
The trucking fleet is replaced very rapidly: the average lifespan of a super-large class truck is eight years, while the median truck on the road today is approximately six years old. In comparison, personal vehicles are replaced on average only every ten and a half years. Moreover, unlike the personal vehicle segment, most long-haul trucks are procured by fleet owners who pay very close attention to the total cost of ownership, not just the sticker price. If hydrogen-fuel trucks become more competitive than their diesel counterparts, there could be a relatively rapid adjustment.
Hydrogen: Here for the long-haul
Hydrogen’s technical and economic fundamentals are likely to improve as technology advances and the Inflation Reduction Act incentivizes investments in renewables. Owing to their renewables potential, large ports, and significant diesel demand, California and Texas are primed to lead the trucking market’s transformation. While trucking fleet turnover will take time, hydrogen appears poised to disrupt the US trucking market.
By: Steven Carlini, VP of Innovation and Data Center View the original article here
In the zero-carbon economy of the future, electricity will become the dominant energy but green hydrogen (and the fuels derived from it) will have a role to play as well. Making green hydrogen viable and abundant will take collaboration, effort, and investment.
Pieces that need to fall into place to make green hydrogen viable
Hydrogen definitely has a role to play in global decarbonization. In the decarbonized world of the future, electricity will become the dominant energy with a 60-70% share in 2050, biofuels will rise, dependence on fossil-based energy will significantly decrease and hydrogen will increase. I want to focus on green hydrogen – derived from water using electrolysis since it is the most promising. In my estimation, green hydrogen will rise between 3 – 10 times the 90 Mt of hydrogen used today by 2050. The 3X – 10X projection goes from a very conservative 270 Mt (3X) to an aggressive 900 Mt (10X). So why is there such a large gap if green hydrogen is the energy source needed for hard-to-abate applications? Mainly because there are 10 significant “pieces” of the puzzle that must come together to produce green hydrogen at the scale needed.
1) Renewable Generation Electricity Capacity – Green hydrogen must be derived through electrolysis which is highly energy intensive. For hydrogen to be green the process must be electrified using a sustainable source (hydro, wind, or solar). How much? The electricity required by 2050 for decarbonized electrification and green hydrogen production of 900 Mt (10X) is estimated to be 130,000 TWh – around 5X today’s total electrical supply of 27,000 TWh. By 2050 using the 900 Mt (10X) green H2 assumption, 30% of electricity use will be dedicated to producing clean hydrogen and its derivatives, such as e-ammonia and e-methanol.
2) Electrolyzer Capacity – Once there is sufficient renewable generation, the capacity of electrolyzer plants needs to match. According to Bloomberg NEF, today’s global electrolyzer capacity of 300 MW must grow to 3000 GW by 2050 to meet clean hydrogen demands of 900 Mt (10X). IEA estimates that every month from January 2030 onwards, three new hydrogen-based industrial plants must be built.
3) Total Cost of green hydrogen – Green hydrogen is fundamentally tied to the cost of renewable electricity, the cost of clean water, CapEx cost of electrolyzer plants, the efficiency of the electrolyzer plant, and finally the cost of storing and transporting the green hydrogen. Today, green hydrogen can cost around €2.5-€5/kg, making it significantly more expensive than the fossil fuel alternatives. Levelized prices need to fall to €1.5/kg by 2050 and possibly sub-€1/kg, to make it competitive with natural gas. However, there are incentives from governments around the world to bring the price down. In the US part of the Inflation Reduction Act created new provisions for clean hydrogen. Under the law, clean hydrogen plants in 2023 can receive a production tax credit up to $3 per kg of hydrogen, for the first 10 years of operation through 2032.
4) Electrolyzer cost – the total installed costs of a GW scale industrial electrolysis plant is currently around 1400 €/kW for Alkaline electrolyzer technology and 1800 €/kW for PEM electrolyzer technology. These need to drop at least 50% by 2050 for green hydrogen to be cost-competitive. However, CapEx improvement plans cannot be a tradeoff resulting in reduced electrolyzer efficiency or durability.
5) Electrolyzer efficiency – Today’s efficiency hovers around 50%. To meet the cost targets, the consensus in the industry is that efficiency needs to continuously improve and be at 75% by 2050. This is a major engineering challenge, plus there is efficiency degradation every year as well.
6) Water Supply – Fresh or clean water must be used in electrolysis. Ocean or salt water (sometimes called seawater) cannot be used. Clean water can be aggregated from collecting rainwater or from a process called desalination. Desalination using reverse osmosis is another very energy-intensive process that also outputs brine (salt-dense water) as a byproduct.
7) Storage – Ideally, electrolysis plants should be located in areas that have abundant renewable electrical power and fresh water. Consumption in the future will likely be places like marinas for ships/vessels and airports for long-haul planes as well as strategic places in the electrical distribution system at the turbine or areas requiring grid stabilization. This means compression, storage, and transportation will be needed. Hydrogen does not degrade over time and can be stored indefinitely. In a gaseous form, it can be stored in ways: pressurized steel tanks and underground reservoirs or salt caverns (for large capacity). Hydrogen can also be liquefied. This would deliver about 75% higher energy density than gaseous hydrogen (stored at 700 bar), But it would waste the equivalent of 25%-30% of the energy contained in the hydrogen to liquefy.
8) Transportation Grid – Moving gaseous hydrogen from the place where it is derived to the place where it will be used is not a straightforward process. There is no piping infrastructure like there is with oil and natural gas pipelines or distribution grids. Because hydrogen is such a small and potentially combustible element, constructing a pipeline is quite challenging.
9) Demand side efficiencies – Just like miles per gallon affects how much fuel a car uses, all applications using electricity or hydrogen need to be made more efficient. A massive effort is required to modernize the existing stock of inefficient assets (buildings, mobility, industrial facilities, and machines, etc.), for higher efficiency or adapt to fun on hydrogen.
10) Funding – In total, investments could amount to almost $15 trillion between now and 2050 – peaking in the late 2030s at around $800 billion per annum1 for 900 Mt (10X). Of this, about $12.5 trillion (85%) relates to the required increase in electricity generation, with only 15% (peaking at almost $150 billion per annum in the late 2030s) relating to an investment in electrolyzer, production facilities, and transport and storage infrastructure. This investment must be coordinated between private-sector action and national and local governments.
The 10 “pieces” of the puzzle that must come together are significant. As with all puzzles, if a single piece is missing, the puzzle is ruined and the 3X scenario would be more likely than the 10X. We have no choice but to put this puzzle together and in this case, we must have all of the pieces in order to meet decarbonization targets and have green hydrogen play its critical role in the effort to halt global warming.
By: Felicity Bradstock View the original article here
There is great optimism around the future of green hydrogen, with many seeing it as a super-fuel that will replace oil-derived options, as well as be highly competitive with electric battery technology. However, we are far from achieving this ambition yet, mainly due to small-scale production operations and high costs. Many companies around the globe have plans to produce green hydrogen, but some are battling challenges that are slowing down the rollout of the clean fuel. Despite improvements in production processes, thanks to greater investment in the sector in recent years, the production and transportation costs of green hydrogen remain much higher than other fuels, including other types of hydrogen.
Producing grey or blue hydrogen, which is derived from fossil fuels, is viewed as relatively low cost, with many companies already relying on this fuel. Grey hydrogen is produced using natural gas. It undergoes a steam methane reforming (SMR) process, which breaks methane apart using high-pressure steam, which creates separate hydrogen, carbon monoxide, and carbon dioxide molecules. This process produces high levels of carbon dioxide, around 9 to 10 tons of CO2 for every ton of hydrogen. But it is also highly cost-effective, so long as natural gas prices remain stable. In July 2022, the cost of grey hydrogen was around $2 per kilo.
In contrast, green hydrogen production methods are more expensive. Green hydrogen is made using renewable energy sources to power an electrolysis process that separates hydrogen from water, producing just steam as a waste product. It is carbon neutral, making it highly attractive for companies looking to decarbonize. However, by July 2022, it cost around $4 to $5 a kilo, or even more, to produce green hydrogen. And some industry experts believe that the high cost of green hydrogen production isn’t going to fall any time soon.
Green hydrogen is viewed by many international agencies, such as the International Energy Agency (IEA) and the International Renewable Energy Agency (IRENA), as a solution to decarbonize ‘hard-to-abate’ sectors. As more governments and private companies around the globe pump funding into green hydrogen operations, there are high hopes that the production cost of green hydrogen to fall substantially, to as low as $0.5 per kilo. However, others believe it will be difficult to drive the cost to lower than $3 per kilo.
IRENA published two studies to drive green hydrogen production worldwide: Green Hydrogen: A Guide to Policy Making in November 2020, and Green Hydrogen Cost Reduction: Scaling up Electrolysers to Meet the 1.5°C climate goal in December 2020. These studies were aimed at encouraging governments and private companies to scale up production, aimed at driving down costs. However, the price of green hydrogen production so far remains elevated, at around 2 to 3 times the cost of grey hydrogen production, when gas prices are stable.
Nevertheless, progress has been seen thanks to greater funding into research and development, with the price of electrolysers falling by around 60 percent since 2010. According to IRENA, they could decrease by a further 40 percent in the short term and by as much as 80 percent in the long term. This cost reduction prediction relies on greater innovation in electrolysis technology to improve its performance, as well as scaling up manufacturing capacity, standardization, and growing economies of scale.
Another challenge to consider is the cost of transportation. Murray Douglas, the head of hydrogen research at Wood Mackenzie, stated that “Hydrogen is pretty expensive to move… “It’s more difficult to move than natural gas … technically, engineering wise … it’s just harder.” And Douglas is not the only one concerned about this. The U.S. Department of Energy (DoE) has reported challenges with green hydrogen including “reducing cost, increasing energy efficiency, maintaining hydrogen purity, and minimizing hydrogen leakage.” The DoE believes greater research is required to “analyze the trade-offs between the hydrogen production options and the hydrogen delivery options when considered together as a system.”
Companies worldwide are now considering the best locations for their green hydrogen production facilities. While there is great potential for the development of plants in Australia, North Africa, and the Middle East, these could be very far from their principal markets. Douglas highlighted the need for a dedicated pipeline, constructed between the producer and end-user if moving green hydrogen by pipe. Alternatively, green hydrogen could be transported as ammonia with nitrogen, which could be shipped and sold to consumers such as fertiliser producers. Otherwise, users would have to crack the ammonia back into nitrogen, which would increase costs and result in energy losses.
For green hydrogen to be as successful as everyone hopes, it will require significant investment to overcome these challenges. Jorgo Chatzimarkakis, the CEO of the industry association Hydrogen Europe, suggests the need for a certification system, to guarantee that any green hydrogen production was powered by renewable sources. Further, a well-researched delivery strategy needs to be developed to ensure that production facilities are adequately linked with green hydrogen markets. This has been seen in projects such as Cepsa’s green hydrogen corridor between southern and northern Europe.
While transportation costs are high, companies already understand how to move green hydrogen as they have been doing it the same way with natural gas for decades. But some are deterred by high costs. Therefore, the industry must drive down production costs to alleviate some of the pressure on transportation. Although the green hydrogen industry continues to face several major challenges, preventing a wide-scale deployment of the clean fuel, greater investment in the sector over the coming decades will likely fix many of these problems and allow for the deployment of global, large-scale green hydrogen production.
The global need for grid-scale energy storage will rise rapidly in the coming years as the transition away from fossil fuels accelerates. Energy storage can help meet the need for reliability and resilience on the grid, but lithium-ion is not the only option, writes Oliver Warren of climate and ESG-focused investment bank and advisory group DAI Magister.
Dubbed the “decade of delivery” by the World Economic Forum (WEF) and the ‘Decade of Action’ by the International Renewable Energy Agency, the 2020s is a crucial decade for the energy transition. However, to realise the full potential of renewables and meet ambitious energy transition objectives, we must have the capacity to store energy more effectively.
Many stakeholders are pinning their long-term storage hopes on lithium-ion (Li-ion) battery storage solutions, with this market expected to grow by almost 20% per year between 2022 and 2023, according to Precedence Research.
But the reality is that, although Li-ion batteries have an important role to play on the road to net zero, this technology is neither robust nor versatile enough to single-handedly fulfil energy storage requirements.
As a result, a diverse range of alternative grid-scale solutions that can deliver an unprecedented expansion in storage capacity are needed to offset our reliance on Li-ion batteries and drive the renewable energy transition.
Ramping up capacity
According to the International Energy Agency (IEA), to decarbonize electricity globally the world’s energy storage capacity must increase by a factor of 40x+ by 2030, reaching a total of 700 GW, or around 25% ofglobal electricity usage (23,000TWh per annum). For comparison, this would be like swelling the size of the UK’s land to that of the USA.
Similar to how “nobody ever gets fired for buying IBM”, lithium-ion holds a similar place in grid scale electrical storage today. With the 2020s being the decade of energy storage, investors need to focus on alternative storage solutions which may require higher capex up front, but deliver lower long term levelized cost of electricity and longer asset lifetime.
Li-ion batteries, long touted as a vital technology for grid-scale storage, are neither feasible nor sustainable. Cobalt extraction, a fundamental component of Li-ion batteries, is highly toxic and polluting. Limited cobalt supply is a major issue, especially considering the rapidly growing demand for electric car batteries and backup generators. Relying solely on Li-ion technology also leaves us vulnerable to a single supply chain and the availability of access to critical elements e.g., cobalt, in some of the most volatile regions of the world, such as the Democratic Republic of the Congo (DRC).
That isn’t to imply that Li-ion batteries don’t have their place, but they should target fast frequency response rather than load following. Li-ion batteries are best suited to replace gas-fired peaking plants e.g., open cycle gas turbines (OCGTs) and supplement pumped hydro during evening peaks. However, they lack the capacity and duration (more than a few hours of drawdown) to load follow, unlike combined cycle gas turbines (CCGTs), throughout the course of a day.
They are also prone to damage from failing to complete full discharge and recharge cycles although battery analytics companies such as PowerUp and Twaice are trying to solve this problem.
In addition, Li-ion batteries have limited lifespans of up to 10 years before needing replacement. All these factors make Li-ion batteries unviable at grid scale and necessitate the use of alternatives.
Vehicle-to-grid (V2G) technology, which will enable the aggregation of part of the storage capacity of the more than 140 million electric vehicles expected globally by 2030, could bring more than 7TWh in Li-Ion-based additional energy storage that can be drawn from at a moment’s notice, but faces the similar limitations as grid based Lithium Ion batteries.
Viable grid-scale storage alternatives
No single killer application or technology exists to get the job done. Diversification is key with success dependent on the wide-scale adoption of multiple grid-scale energy storage solutions:
Compressed air/gas storage
New compressed air and gas storage technologies offer a novel way of storing energy as compressed air or gas. They can store more energy in a smaller space and for more extended periods than other forms of energy storage like batteries.
Italian start-up Energy Dome has found an unexpected way to store green energy. The company’s ground-breaking long-duration energy storage system compresses CO2 into a liquid and stores it in a massive, pressurised dome. CO₂ has a higher density than air which results in denser energy storage and doesn’t need advanced materials and expensive insulation compared to liquid air at cryogenic temperatures.
Augwind Energy is an Israeli technology company revolutionizing energy storage at scale by storing compressed air underground in large tanks made from unique polymers. The company’s AirBattery solution uses only air and water to store energy safely and cost-effectively at high capacity for long durations.
The solution uses an external energy source, be it from the grid or renewable sources to power water pumps. AirBattery can run endless cycles for decades with no degradation and at a minimal cost.
Cheesecake Energy is a UK-based spinout company founded on thermal and mechanical energy storage research undertaken at the University of Nottingham. The company has developed eTanker, a new energy storage system that stores electricity as heat and compressed air. Electric motors operate compressors that store air and heat at high pressure in storage units to store energy. To produce electricity, the same compressors act as expanders, which turn a generator.
The eTanker is a long-lasting (20+ years) and environmentally friendly energy storage solution built from recyclable raw materials. It can deploy across a variety of static applications such as industry, agriculture, transport, and renewable generation, replacing the need for lithium-ion batteries.
Highview Power also hails from the United Kingdom. The company has developed a large-scale energy storage system for utility and distribution power networks. Highview’s low-cost liquid-air energy storage solution uses the process of cryogenic cooling to store energy for future use.
The system gathers energy from renewable sources like wind and solar and stores it in tanks as liquid air at low temperatures. Liquid air gets heated when required, causing the stored energy to release as a gas. This gas is then used to generate electricity by powering turbines.
Highview plans to raise £400 million (US$483.5 million) to build the world’s first commercial-scale liquid air energy storage (LAES) plant to boost renewable power generation in the UK. Of the £400 million, the company intends to spend £250 million to construct a 30MW storage plant that can store 300MWh of electricity. The remaining £150 million would go towards engineering for a further four sites. Highview already has a 5MW pilot plant in operation in England.
Innovative pumped hydro
Innovative pumped hydro energy storage (PHES) uses renewable energy to pump water from a lower reservoir to an upper reservoir. During periods of high demand, the water releases from the upper reservoir to generate electricity. This type of energy storage is more efficient and cost-effective than traditional pumped hydro and requires less land.
Ocean Grazer, a Dutch start-up, has come up with a unique offshore energy storage system that can deploy at the source of power generation. The Ocean Battery is a pumped hydro system that stores energy from offshore wind farms by pumping water back and forth into flexible bladders where it is stored at different pressures. When there is a demand for power, water rushes back from the bladders to the reservoirs driving multiple hydro turbines to generate electricity.
The Ocean Battery is significantly less expensive to build than existing large-scale lithium-ion battery systems, which require massive platforms made from sea containers. Furthermore, the Ocean Battery has a far longer lifespan, lasting up to one million charging cycles, compared to the 5,000-10,000 offered by lithium-ion batteries.
RheEnergise has developed a ‘High-Density Hydro’ system that stores and releases electricity from hills rather than mountains or dam walls. In contrast to other systems, it uses a non-toxic, high-density additive for its closed-loop pumped storage. This allows it to create 2.5x the energy of traditional pumped storage systems while also having reduced environmental impacts and lower costs.
The High-Density Hydro system has the potential to enable hillsides across the UK to store energy for the country’s electricity supply, considerably expanding the range and output of pumped storage. The company expects to have its first commercial system operational by 2024.
Thermal energy storage
Thermal energy storage works by storing thermal energy as heat, usually in a material such as water, rock, or soil. Heat gets stored in various ways, including using phase-change materials, which absorb and release heat at specific temperatures. The stored heat can then generate electricity. Thermal energy storage can store excess energy from solar, wind, or other renewable sources during peak energy demand hours or when the renewable source is unavailable
Lumenion is a renewable energy storage technology company that provides large-scale energy storage solutions. The company’s TESCORE solution is a high-temperature storage system that stores fluctuating wind and solar PV power as thermal energy with virtually loss-free conversion.
Japanese companies Toshiba, Marubeni and Chubu Electric Power have collaborated with the support of the Japanese Ministry of the Environment to develop a pilot rock-based thermal energy storage system that’s more environmentally friendly and efficient than lithium-ion batteries and hydrogen.
The system has a capacity of 100kWh and can use storage materials such as crushed stone, bricks, molten salt, and concrete. Thus far, it’s claimed that the system can store heat at temperatures above 700°C with a small heat storage tank.
Over the next few years, the goal is to build a larger facility with 500kWh capacity and launch commercial projects based on rock heat storage technology.
Gravity storage
Gravity storage is a form of energy storage that utilizes the force of gravity to store and release potential energy. It works by raising weights, typically made of concrete, bricks, or rocks, and then releasing them to generate electricity when needed.
Energy Vault, based out of Switzerland, is a market leader in gravity storage. The company’s breakthrough technology was inspired by pumped hydro plants that rely on the power of gravity and movement of water to store and discharge electricity.
Their solution employs a proprietary mechanical process and energy management system to store and dispatch electricity. When renewable energy generation is high, the solution harnesses that energy to lift 30-tonne bricks to an elevated height with potential energy stored in the bricks. The system releases kinetic energy back to the grid through the controlled lowering of the bricks under gravitational force to generate electricity.
The management system orchestrates the energy charge/discharge while accounting for various factors, including energy supply and demand volatility, weather elements and other variables.
Storage is a fundamental enabler of the energy transition
Our ability to expand energy storage capacity is one of the most pressing issues that will determine whether this defining ‘transitional’ decade is a success. But we’ll need to invest wisely into the right technologies that get the greatest bang for the buck (in terms of GWh capacity and return on capital) given the limited lifespan of Li-Ion and the decarbonization of the grid.
At a current capital cost of US$2,000 per kW quoted by the US National Renewable Energy Laboratory (NREL) for 6-hour Li-ion battery storage, the 700GW of capacity needed by 2030 equates to around a US$1.5 trillion market over the coming decade, making it worth nearly US$200 billion a year.
Annual investment worldwide into promising energy storage companies is currently running at only US$9 billion in 2022 according to Pitchbook. As the crucial nature of this market becomes more and more clear to investors, there needs to be an exponential increase in investment. Within energy transition, the market for energy storage offers one of the largest ‘blue-ocean’ opportunities for investors available anywhere in the world today.
By: Casey Crownhart View the original article here
Buckle up, because this week, we’re talking about batteries.
Over the past couple of months, I’ve been noticing a lot of announcements about a new type of battery, one that could majorly shake things up if all the promises I’m hearing turn out to be true.
The new challenger? Sodium-ion batteries, which swap sodium for the lithium that powers most EVs and devices like cell phones and laptops today.
Sodium-ion batteries could squeeze their way into some corners of the battery market as soon as the end of this year, and they could be huge in cutting costs for EVs. I wrote a story about all the recent announcements, and you should give it a read if you’re curious about what companies are jumping in on this trend and what their plans are. But for the newsletter this week, let’s dig a little bit deeper into the chemistry and consider what the details could mean for the future of EV batteries.
Top dog
One of the reasons that lithium dominates batteries today is absolutely, maddeningly simple: it’s small.
I mean that in the most literal, atomic sense. Lithium is the third-lightest element, heavier than only hydrogen and helium. When it comes down to it, it’s hard to beat the lightest metal in existence if you’re trying to make compact, lightweight batteries.
And cutting weight and size is the goal for making everything from iPhones to EVs: a lightweight, powerful battery means your phone can be smaller and your car can drive farther. So one of the primary ways we’ve measured progress for batteries is energy density—how much energy a battery can pack into a given size.
When you look at that chemical reality, it’s almost no wonder that lithium-ion batteries have exploded in popularity since their commercial debut in the 1990s. There are obviously other factors too, like lithium-ion’s ability to reach high voltages in order to deliver a lot of power, but the benefit of being lightweight and portable is hard to overstate.
Lithium-ion batteries have also benefited from being the incumbent. There are countless researchers scouring the world for new materials and new ways to build lithium-ion cells, and plenty of companies making them in greater numbers—all of which adds up to greater efficiencies. As a result, costs have come down basically every year for decades (with the notable exception of 2022).
And at the same time, energy density is ticking up, a trend I’m personally grateful for because I often forget to charge my phone for days at a time, and it typically works out much better when that happens now than it did a few years ago.
Branching out
But just because lithium-ion dominates the battery world today doesn’t mean it’ll squash the competition forever.
I’ve written about the growing number of options in the battery industry before, mostly in the context of stationary storage on the electrical grid. This is especially important in the transition to intermittent renewable energy sources like wind and solar.
While backup systems tend to use lithium-ion batteries today since they’re what’s available, many companies are working to build batteries that could eventually be even cheaper and more robust. In other words, many researchers and companies want to design batteries specifically for stationary storage.
New batteries could be made with abundant materials like iron or plastic, for example, and they might use water instead of organic solvents to shuttle charge around, addressing lingering concerns about the safety of large-scale lithium-ion battery installations.
But compared to stationary storage, there are fewer candidates that could work in EV batteries, because of the steep demands we have for our vehicles. Today, most of the competition in the commercial market is between the different flavors of lithium-ion batteries, with some lower-cost versions that don’t contain cobalt and nickel gaining ground in the last couple of years.
That could change soon too, though, because just below lithium on the periodic table, a challenger lurks: sodium. Sodium is similar to lithium in some ways, and cells made with the material can reach similar voltages to lithium-ion cells (meaning the chemical reactions that power the battery will be nearly as powerful).
And crucially, sodium-based batteries have recently been cramming more energy into a smaller package. In 2022, the energy density of sodium-ion batteries was right around where some lower-end lithium-ion batteries were a decade ago—when early commercial EVs like the Tesla Roadster had already hit the road.
Projections from BNEF suggest that sodium-ion batteries could reach pack densities of nearly 150 watt-hours per kilogram by 2025. And some battery giants and automakers in China think the technology is already good enough for prime time. For more on those announcements and when we might see the first sodium-battery-powered cars on the road, check out my story on the technology.
Related reading
Here’s how sodium batteries could get their start in EVs.
I wrote about the potential for this sort of progress in a story from January about what we might see forbatteries this year.
Sodium could be competing with low-cost lithium-ion batteries—these lithium iron phosphate batteries figure into a growing fraction of EV sales.
Take a tour of some other non-lithium-based batteries:
Iron-based batteries could be a cheap way to store energy on the grid and assuage concerns about safety.
What about using plastic instead?
Some companies want to go beyond batteries entirely to store energy.
Another thing
A startup says it’ll be ready to turn on the world’s first fusion power plant in five years. Yes, you read that right: five years.
Helion Energy, a fusion startup backed by OpenAI’s Sam Altman, announced that it’s lined up an agreement to sell electricity to Microsoft. The company says its first plant will come online in 2028 and will reach full capacity (50 megawatts of output) within a year after that.
As you might remember, the energy world reached a huge milestone in December when a fusion reaction generated more energy than what was put in to start it. But for a lot of reasons, that symbolic moment doesn’t necessarily mean cheap fusion power is within our grasp. And some experts are pretty skeptical about Helion’s announcement. Read more about the details in this story from my colleague James Temple.
Keeping up with climate
Need a few extra miles of range on your EV? Might as well slap some solar panels on the roof. But don’t expect too much of a boost. (Bloomberg)
For the first time in my entire life, I seem to be experiencing seasonal allergies. And climate change might have something to do with it. (The Atlantic)
Companies might be overselling the potential for so-called “renewable natural gas.” While it can cut emissions relative to fossil sources, critics worry that putting too much stock in methane made from cow manure or food scraps will slow efforts to ditch fossil fuels. (Canary Media)
→ I wrote earlier this year about how the process to make and capture methane from food scraps works. (MIT Technology Review)
Aubrey Plaza is hilarious and a gift to this world, but some people aren’t so happy about a recent ad she did for the dairy industry that takes aim at plant-based milks. (Vox)
India might stop adding new coal power plants to the pipeline. While this wouldn’t stop all current construction, it could be a major boost to the country’s emissions cuts. (Reuters)
A lot of the work to improve battery performance has been basically focused on one half of the device: the cathode. But some companies are working hard to improve the often-overlooked anodes by using silicon. (IEEE Spectrum)
→ Silicon anodes from startup Sila made their debut in fitness trackers nearly two years ago. The next stop? EVs. (MIT Technology Review)
Support for nuclear power in the US just reached its highest level in over a decade, according to a new Gallup poll. (Grist)
Electric vehicles made up 80% of Norway’s new car sales last year. The country provides a picture of the potential future for electrified transport’s benefits (cleaner air!) and challenges (long charging lines). (New York Times)
By: Catherine Clifford View the original article here
Service technicians work to install the foundation for a transmission tower at the CenterPoint Energy power plant on June 10, 2022 in Houston, Texas. Brandon Bell | Getty Images News | Getty Images
Building new transmission lines in the United States is like herding cats. Unless that process can be fundamentally improved, the nation will have a hard time meeting its climate goals.
The transmission system in the U.S. is old, doesn’t go where an energy grid powered by clean energy sources needs to go, and isn’t being built fast enough to meet projected demand increases.
Building new transmission lines in the U.S. takes so long — if they are built at all — that electrical transmission has become a roadblock for deploying clean energy.
“Right now, over 1,000 gigawatts worth of potential clean energy projects are waiting for approval — about the current size of the entire U.S. grid — and the primary reason for the bottleneck is the lack of transmission,” Bill Gates wrote in a recent blog post about transmission lines.
The stakes are high.
Herding cats with competing interests
Building new transmission lines requires countless stakeholders to come together and hash out a compromise about where a line will run and who will pay for it.
There are 3,150 utility companies in the country, the U.S. Energy Information Administration told CNBC, and for transmission lines to be constructed, each of the affected utilities, their respective regulators, and the landowners who will host a line have to agree where the line will go and how to pay for it, according to their own respective rules.
Aubrey Johnson, a vice president of system planning for the Midcontinent Independent System Operator (MISO), one of seven regional planning agencies in the U.S., compared his work to making a patchwork quilt from pieces of cloth.
“We are patching and connecting all these different pieces, all of these different utilities, all of these different load-serving entities, and really trying to look at what works best for the greatest good and trying to figure out how to resolve the most issues for the most amount of people,” Johnson told CNBC.
What’s more, the parties at the negotiating table can have competing interests. For example, an environmental group is likely to disagree with stakeholders who advocate for more power generation from a fossil-fuel-based source. And a transmission-first or transmission-only company involved is going to benefit more than a company whose main business is power generation, potentially putting the parties at odds with each other.
The system really flounders when a line would span a long distance, running across multiple states.
States “look at each other and say: ‘Well, you pay for it. No, you pay for it.’ So, that’s kind of where we get stuck most of the time,” Rob Gramlich, the founder of transmission policy group Grid Strategies, told CNBC.
“The industry grew up as hundreds of utilities serving small geographic areas,” Gramlich told CNBC. “The regulatory structure was not set up for lines that cross 10 or more utility service territories. It’s like we have municipal governments trying to fund an interstate highway.”
This type of headache and bureaucratic consternation often prevent utilities or other energy organizations from even proposing new lines.
“More often than not, there’s just not anybody proposing the line. And nobody planned it. Because energy companies know that there’s not a functioning way really to recover the costs,” Gramlich told CNBC.
Electrical transmission towers during a heatwave in Vallejo, California, US, on Sunday, Sept. 4, 2022. Blisteringly hot temperatures and a rash of wildfires are posing a twin threat to California’s power grid as a heat wave smothering the region peaks in the days ahead. Photographer: David Paul Morris/Bloomberg via Getty Images
Who benefits, who pays?
Energy companies that build new transmission lines need to get a return on their investment, explains James McCalley, an electrical engineering professor at Iowa State University. “They have got to get paid for what they just did, in some way, otherwise it doesn’t make sense for them to do it.”
Ultimately, an energy organization — a utility, cooperative, or transmission-only company — will pass the cost of a new transmission line on to the electricity customers who benefit.
“One principle that has been imposed on most of the cost allocation mechanisms for transmission has been, to the extent that we can identify beneficiaries, beneficiaries pay,” McCalley said. “Someone that benefits from a more frequent transmission line will pay more than someone who benefits less from a transmission line.”
But the mechanisms for recovering those costs varies regionally and on the relative size of the transmission line.
Regional transmission organizations, like MISO, can oversee the process in certain cases but often get bogged down in internal debates. “They have oddly shaped footprints and they have trouble reaching decisions internally over who should pay and who benefits,” said Gramlich.
The longer the line, the more problematic the planning becomes. “Sometimes its three, five, 10 or more utility territories that are crossed by needed long-distance high-capacity lines. We don’t have a well-functioning system to determine who benefits and assign costs,” Gramlich told CNBC. (Here is a map showing the region-by-region planning entities.)
Johnson from MISO says there’s been some incremental improvement in getting new lines approved. Currently, the regional organization has approved a $10.3 billion plan to build 18 new transmission projects. Those projects should take seven to nine years instead of the 10 to 12 that is historically required, Johnson told CNBC.
“Everybody’s becoming more cognizant of permitting and the impact of permitting and how to do that and more efficiently,” he said.
There’s also been some incremental federal action on transmission lines. There was about $5 billion for transmission-line construction in the IRA, but that’s not nearly enough, said Gramlich, who called that sum “kind of peanuts.”
The U.S. Department of Energy has a “Building a Better Grid” initiative that was included in President Joe Biden’s Bipartisan Infrastructure Law and is intended to promote collaboration and investment in the nation’s grid.
In April, the Federal Energy Regulatory Commission issued a notice of proposed new rule, named RM21-17, which aims to address transmission-planning and cost-allocation problems. The rule, if it gets passed, is “potentially very strong,” Gramlich told CNBC, because it would force every transmission-owning utility to engage in regional planning. That is if there aren’t too many loopholes that utilities could use to undermine the spirit of the rule.
What success looks like
Gramlich does point to a couple of transmission success stories: The Ten West Link, a new 500-kilovolt high-voltage transmission line that will connect Southern California with solar-rich central Arizona, and the $10.3 billion Long Range Transmission Planning project that involves 18 projects running throughout the MISO Midwestern region.
“Those are, unfortunately, more the exception than the rule, but they are good examples of what we need to do everywhere,” Gramlich told CNBC.
This map shows the 18 transmission projects that make up the $10.3 billion Long Range Transmission Planning project approved by MISO. Map courtesy MISO
In Minnesota, the nonprofit electricity cooperative Great River Energy is charged with making sure 1.3 million people have reliable access to energy now and in the future, according to vice president and chief transmission officer Priti Patel.
“We know that there’s an energy transition happening in Minnesota,” Patel told CNBC. In the last five years, two of the region’s largest coal plants have been sold or retired and the region is getting more of its energy from wind than ever before, Patel said.
Great River Energy serves some of the poorest counties in the state, so keeping energy costs low is a primary objective.
“For our members, their north star is reliability and affordability,” Patel told CNBC.
An representative of the Northland Reliability Project, which Minnesota Power and Great River Energy are working together to build, is speaking with community members at an open house about the project and why it is important. transmission lines, energy grid, clean energy
Great River Energy and Minnesota Power are in the early stages of building a 150-mile, 345 kilovolt transmission line from northern to central Minnesota. It’s called the Northland Reliability Project and will cost an estimated $970 million.
It’s one of the segments of the $10.3 billion investment that MISO approved in July, all of which are slated to be in service before 2030. Getting to that plan involved more than 200 meetings, according to MISO.
The benefit of the project is expected to yield at least 2.6 and as much as 3.8 times the project costs, or a delivered value between $23 billion and $52 billion. Those benefits are calculated over a 20-to-40-year time period and take into account a number of construction inputs including avoided capital cost allocations, fuel savings, decarbonization and risk reduction.
The cost will eventually be borne by energy users living in the MISO Midwest subregion based on usage utility’s retail rate arrangement with their respective state regulator. MISO estimates that consumers in its footprint will pay an average of just over $2 per megawatt hour of energy delivered for 20 years.
But there is still a long process ahead. Once a project is approved by the regional planning authority — in this case MISO — and the two endpoints for the transmission project are decided, then Great River Energy and Minnesota Power are responsible for obtaining all of the land use permits necessary to build the line.
“MISO is not going to be able to know for certain what Minnesota communities are going to want or not want,” Patel told CNBC. “And that gives the electric cooperative the opportunity to have some flexibility in the route between those two endpoints.”
For Great River Energy and Minnesota Power, a critical component of engaging with the local community is hosting open houses where members of the public who live along the proposed route meet with project leaders to ask questions.
For this project, the utilities specifically planned the route of the transmission to run along a previously existing corridors as much as possible to minimize landowner disputes. But it’s always a delicate subject.
A map of the Northland Reliability Project, which is one of 18 regional transmission projects approved by MISO, the regional regulation agency. It’s estimated to cost $970 million. Map courtesy Great River Energy
“Going through communities with transmission, landowner property is something that is very sensitive,” Patel told CNBC. “We want to make sure we understand what the challenges may be, and that we have direct one-on-one communications so that we can avert any problems in the future.”
At times, landowners give an absolute “no.” In others, money talks: the Great River Energy cooperative can pay a landowner whose property the line is going through a one-time “easement payment,” which will vary based on the land involved.
“A lot of times, we’re able to successfully — at least in the past — successfully get through landowner property,” Patel said. And that’s due to the work of the Great River Energy employees in the permitting, siting and land rights department.
“We have individuals that are very familiar with our service territory, with our communities, with local governmental units, and state governmental units and agencies and work collaboratively to solve problems when we have to site our infrastructure.”
Engaging with all members of the community is a necessary part of any successful transmission line build-out, Patel and Johnson stressed.
At the end of January, MISO held a three-hour workshop to kick off the planning for its next tranche of transmission investments.
“There were 377 people in the workshop for the better part of three hours,” MISO’s Johnson told CNBC. Environmental groups, industry groups, and government representatives from all levels showed up and MISO energy planners worked to try to balance competing demands.
″And it’s our challenge to hear all of their voices, and to ultimately try to figure out how to make it all come together,” Johnson said.
By: Catherine Clifford View the original article here
Heavy electrical transmission lines at the powerful Ivanpah Solar Electric Generating System, located in California’s Mojave Desert at the base of Clark Mountain and just south of this stateline community on Interstate 15, are viewed on July 15, 2022 near Primm, Nevada. The Ivanpah system consists of three solar thermal power plants and 173,500 heliostats (mirrors) on 3,500 acres and features a gross capacity of 392 megawatts (MW). George Rose | Getty Images News | Getty Images
Wind and solar power generators wait in yearslong bureaucratic lines to connect to the power grid, only to be faced with fees they can’t afford, forcing them to scramble for more money or pull out of projects completely.
This application process, called the interconnection queue, is delaying the distribution of clean power and hampering the U.S. in reaching its climate goals.
The interconnection queue backlog is a symptom of a larger climate problem for the United States: There are not enough transmission lines to support the transition from a fossil fuel-based electric system to a decarbonized energy grid.
Surprise fee increases
The Oceti Sakowin Power Authority, a nonprofit governmental entity owned by seven Sioux Indian tribes, is working to build 570 megawatts of wind power generation to sell to customers in South Dakota.
“Economic development through renewable energy speaks to the very heart of Lakota culture and values – being responsible stewards of Grandmother Earth, Unci Maka,” Jonathan E. Canis, general counsel for the Oceti Sakowin Power Authority, told CNBC. “Together our tribes occupy almost 20% of the land area of South Dakota. And the experts who have been measuring our wind resources literally describe them as ‘screamin.’.”
To connect wind power generation to the electric grid and make money from the sale of that power, the Oceti Sakowin Power Authority — like every electricity generator in the U.S. — has to submit an application called an interconnection request to whichever organization is overseeing the coordination of the electric grid in that region. Sometimes it’s a regional transmission planning authority, other times a utility.
This photo shows the rangeland on the Cheyenne River Reservation with the Missouri River in the distance. The Oceti Sakowin Power Authority wants to build two wind power projects and the Ta’teh Topah project, planned to be 450 megawatts, is the larger of two wind projects. The transmission tie-line for the Ta’teh Topah project will cross the rangeland and the river to interconnect with a Basin Electric transmission line east of the Missouri River. Photo courtesy Oceti Sakowin Power Authority.
In late 2017, the Oceti Sakowin Power Authority paid a $2.5 million deposit to secure a place in line for its application to be reviewed by the Southwest Power Pool, a regional grid operator.
Five years later, in 2022, the Southwest Power Pool came back and told it that the fee to connect to the grid would actually be $48 million. That’s because connecting all that new power to the grid would require major updates to the transmission infrastructure.
The Oceti Sakowin Power Authority had 15 business days to come up with the extra $45.5 million.
“Needless to say, we couldn’t do it and had to drop out,” Canis told CNBC.
Now, the Oceti Sakowin Power Authority is reevaluating the size and composition of the project and plans to reenter the interconnection queue by the end of the year. That could mean another yearslong wait in line.
These burdens are typical.
In 2020, Pine Gate Renewables had a solar project located in the Piedmont region of North Carolina that it expected to cost $5 million to connect to the electric grid. The local utility in charge of overseeing the interconnection process told Pine Gate it would be more than $30 million. Pine Gate had to terminate the project because it couldn’t afford the new fees, its vice president of regulatory affairs, Brett White, told CNBC.
“We view, as a company, the interconnection problem as the biggest impediment to the industry right now and the costs associated with interconnection are the biggest reason that a project dies on the vine,” White said. “It’s the biggest wild card you have going into the project development cycle.”
There are efforts underway to improve the efficiency of the process, but they’re fundamentally putting a Band-Aid on top of an even deeper problem in the United States: There isn’t enough transmission infrastructure to support the energy transition from fossil fuel sources of energy to clean sources of energy.
“You could make the process for the queue as efficient and pristine as possible and it still could not be all that effective because at some point you’re going to run out of transmission headroom,” Wood Mackenzie analyst Ryan Sweezey told CNBC.
This photo shows the Western Area Power Administration’s substation in Martin South Dakota on the Pine Ridge Reservation where the 120 megawatt Pass Creek project, the smaller of the two wind power projects Oceti Sakowin Power Authority is trying to stand up, will interconnect if the project can move forward. Photo courtesy Oceti Sakowin Power Authority.
Waiting in line
The entire electric grid in the U.S. has installed capacity of 1,250 gigawatts. There are currently 2,020 gigawatts of capacity in the interconnection queue lines around the country, according to a report published Thursday by the Lawrence Berkeley National Laboratory. That includes 1,350 gigawatts of power capacity, mostly clean, looking to be constructed and connected to the grid. The rest, 670 gigawatts, is for storage.
In 2022, the active energy capacity in interconnection queues in the U.S. is about 2,020 gigawatts and exceeds the installed capacity of entire U.S. power plant fleet, which is about 1,250 gigawatts, according to the report on interconnection queues out of Lawrence Berkeley National Laboratory published Thursday. Chart courtesy Joseph Rand at Lawrence Berkeley National Laboratory.
Berkeley Lab pulls interconnection queue data from all of the regional planning territories in the United States and from between 35 and 40 utilities that are not covered by areas with regional planning authorities. The data covers between 85% and 90% of the electricity load in the United States, Joseph Rand, an energy policy researcher and the lead author of the study, told CNBC.
The interconnection process starts with a request to connect to the grid, which officially enters the power generator in the interconnection queue. The next step is a series of studies — the feasibility, system and facilities studies — where the grid operator determines what equipment or upgrades will be necessary to get the new power generation on the grid and what it will cost.
If all the parties can agree, then the power generator and grid operator reach an interconnection agreement, which establishes the grid improvements the power generator will pay for.
The total power capacity that comes out from a fossil fuel-burning power plant is often much greater than the capacity from renewable plants. That means it can take multiple wind or solar power generation plants — and, therefore, interconnection requests — to get the same units of energy online.
A single natural gas plant could be 1,200 megawatts, Sweezey told CNBC. “That’s one request — 1,200 megawatts,” Sweezey said. “Whereas usually if you’re going to get that same amount of capacity with renewables, that’s going to be six, seven, eight, nine, 10 different projects. So that’s 10 different requests in the queue.”
On average, it took a new power generation project 35 months to go from the interconnection request being filed with a grid operator to an interconnection agreement being reached in 2022, according to Berkeley Lab.
The amount of electricity generation in queues by region by type of power, according to the report on interconnection queues out of Lawrence Berkeley National Laboratory published Thursday. Chart courtesy Joseph Rand at Lawrence Berkeley National Laboratory.
How did this process become such a problem?
The U.S. energy grid is a patchwork system of many regional utility companies. Some provide transmission services and some don’t.
In an effort to promote competition, the Federal Energy Regulatory Commission issued an order in 1996 saying transmission service has to be provided to power generators on a nondiscriminatory basis. This allowed all kinds of power generators, including those that do not own transmission infrastructure, to compete. In 2003, it issued another order that standardized the interconnection process for energy generators.
Both orders “attempted to make the services one needs nondiscriminatory and fair to all users, for their respective service,” according to Rob Gramlich, founder of transmission market intelligence firm Grid Strategies.
This is a simplified visualization of the interconnection queue study process. Chart courtesy the Government Accountability Office and Lawrence Berkeley National Laboratory.
That process worked well enough when the power generation industry was building large, centrally located energy plants that burned fossil fuels. But the process started to show signs of strain around 2008 when renewable energy started to come online in places where there was not sufficient transmission, Gramlich told CNBC. In April 2008, MISO, one of the regional operators, said it would take 42 years, until 2050, for it to get through its interconnection queue.
Reforms in 2008 and 2012 helped a little bit, Gramlich told CNBC. “But I think everybody’s realizing now that that original process is fundamentally unsuited to the new generation mix.”
The interconnection process is especially bad at estimating battery storage, said White. That’s because transmission planning is always defaulting to the worst-case scenario, but batteries will draw energy from the grid when the demand is low and energy prices are low, and then use that stored power when the grid is at or near capacity. Using worst-case-scenario planning for battery storage fundamentally misses the point of a battery.
“The upgrades that are going to be triggered on the system are going to be very, very extensive and very, very expensive. And so they hand you a bill that reflects that,” White told CNBC.
But that kind of system upgrade “in our mind is totally disassociated from the economics of the asset, and not really looking at the benefit that the project is going to provide to the system,” White said.
Texas makes it easier
The rates of interconnection applications that actually reach commercial completion vary significantly, but none are higher than 38% in the New England region, according to Berkeley Lab. The Texas grid operator, Electric Reliability Council of Texas, or ERCOT, has a completion rate of 31% and is the only other region with a completion rate of over 30%.
On the low end, the California Independent System Operator region has an 13% completion rate and the New York Independent System Operator region is at 15%.
This chart shows the share of projects that requested interconnection from 2000 to 2017 that have reached a commercial operation date. Chart courtesy Joseph Rand at Lawrence Berkeley National Laboratory.
The low percentage of interconnection requests that actually get built is partly because of the high cost to connect.
In the MISO region, for instance, interconnection costs were generally less than $100 per kilowatt-hour from 2008 to 2016, but have risen to a few hundred dollars per kWh for wind and solar, with spikes as high as $1,000 per kWh in some parts of the region, Gramlich told CNBC.
Adding even small amounts of energy to the grid requires infrastructure improvements because it’s nearly at capacity. Pushing those costs onto the builders of individual renewable projects generally makes them economically unsustainable.
“Those projects ended up withdrawing from the queue or terminating, because they don’t pencil anymore,” White told CNBC.
Some of the completion rates are artificially low because developers don’t actually expect to complete them all, but instead shop the same project around to various regional grid operators to get the best deal — what’s called “speculative queuing,” Sweezey told CNBC. It’s not expensive to get into queues, so developers submit applications to get information about which location will require the least expensive upgrades.
For grid operators, having power generators stuff their queues is overwhelming an already taxed system.
“Projects that have come through the process are not being built and becoming operational,” Jeffrey Shields, a PJM Interconnection spokesperson, told CNBC. “There are about 38,000 MW of renewable projects that have no further PJM requirements but are not being built because of siting, supply chain, or other issues facing the industry that are not related to PJM’s interconnection process.”
The long application timelines and expensive upgrades have made Texas a desirable place to build renewable energy projects because the state has its own interconnection application process.
“There is Texas, and then there’s the rest of the country with respects to interconnection,” White of Pine Gate told CNBC. Texas doesn’t require the same level of network upgrades to get power generation connected to the grid so getting a project online in Texas is faster and lower cost than the rest of the country, White said.
“You can put a project in the PJM queue tomorrow and it may not get constructed and built until 2030, whereas if you do the same with the Texas project, right now, it’s probably online in two to three years. So it’s just a much, much shorter timeline to commercial operation for a project in Texas,” White told CNBC.
But Texas also has a unique risk because ERCOT can decide to limit the amount of power that a generator can sell to the market if a particular electric corridor gets overly congested.
“It’s a bit of a double-edged sword,” White told CNBC. But with infrastructure deals, “time kills deals, time kills projects,” White said, so energy developers may prefer to take the risk and get the deal done.
Huge clouds and transmission towers are seen from Highway 5 in Kern County of California, United States on April 2, 2023. Anadolu Agency | Anadolu Agency | Getty Images
How does this situation get fixed?
In June 2022, FERC issued a proposal on interconnection reforms to address queue backlogs and has since received a slew of public comments.
“We understand that 80 to 85 percent of the projects that are waiting in the queue ultimately are not being built. I think FERC has an opportunity here to make sure that we unlock that bottleneck and that we do all that we can to move those projects forward,” FERC Chairman Willie Phillips said on March 16, according to a statement provided by a FERC spokesperson.
The proposed rule change would offer incremental improvements, like providing information to developers so they can make more informed siting decisions without flooding the queue with speculative requests, and imposing more strict mandates on the regional grid operators to complete studies in a given time period, Rand of Berkeley Lab told CNBC.
“I do think what FERC is proposing has the potential to improve this situation,” Rand told CNBC. But fundamentally, these iterative changes won’t be a silver bullet.
“The energy transition is here. But our updating and expansion of our electric transmission system so far has not even remotely kept pace with that velocity, rate of change we are seeing on the generator-supply side,” said Rand.
There’s also a shortage of the kinds of electrical and transmission engineers required to process all of these applications, Sweezey and White told CNBC. “There’s just not enough people and so we have to think about what is the smartest way to maximize that expertise. And that means getting those engineers out of some of the rote manual data entry and into the actual analysis,” White told CNBC.
Another option is building new sources of clean energy that can be constructed closer to where demand is needed, like small nuclear reactors, Sweezey told CNBC. “I just don’t think people have come to that realization yet.”
Building sufficient transmission to support the energy transition is not necessarily a technical challenge as much as it is a political one.
“The type of coordination and planning that’s required for this kind of large-scale transmission — this involves maybe multiple utilities, multiple grid operators, multiple states, cities, counties, everything, even the feds are all involved — and that is antithetical to the U.S. as structured as a decentralized nation,” Sweezey told CNBC.
But the stakes are high.
“Even with all of the work, with all this great stuff that’s in the IRA and all of the wind that is in the sails of decarbonization in the renewable industry, if you can’t address transmission and infrastructure, then those goals aren’t going to be met,” White told CNBC.
“It really is the bottleneck that’s preventing that from happening.”
Regulators and policymakers must resist the temptation to overcommit to hydrogen for end uses where electrification will ultimately win out.
By: Dan Esposito and Hadley Tallackson View the original article here
This opinion piece is part of a series from Energy Innovation’s policy experts on advancing an affordable, resilient and clean energy system. It was written by Dan Esposito, senior policy analyst in Energy Innovation’s Electricity Program, and Hadley Tallackson, a policy analyst in the Electrification Program at Energy Innovation.
The Inflation Reduction Act has upended hydrogen economics, making “green” hydrogen — electrolyzed from renewable electricity and water — suddenly cost-competitive with its natural gas-derived counterpart.
On the supply side, electrolyzers can help utilities integrate renewables into the grid, speeding the clean electricity transition. On the demand side, electrolysis can cost-effectively decarbonize hydrogen production.
But the new hydrogen economics mean regulators and policymakers must be even more careful to avoid directing the fuel to counterproductive applications like heating buildings.
“Gray” hydrogen, which uses the highly-polluting steam methane reformation, or SMR, process, has long been the cheapest production method, trading around $1.50-2.00 per kilogram in the United States. In comparison, electrolyzed hydrogen costs about $4-8/kg without subsidies. The Inflation Reduction Act’s $3/kg incentive for zero-carbon hydrogen makes green hydrogen cheaper than gray, potentially spurring an electrolyzer boom.
To facilitate utilities connecting newly-cheap electrolyzers to the grid, regulators should set tariffs reflecting their flexibility value, empowering more bullish utility wind and solar resource procurement.
However, cheap hydrogen should not encourage its use in applications better served by direct electrification like buildings or transportation. Regulators should remain wary of gas utility proposals to blend hydrogen into pipelines, as they would achieve few emissions reductions before facing costly dead-ends while increasing threats to public safety. State policymakers should also use caution before directing public funds toward hydrogen light-duty refueling stations, as electric vehicles have substantial cost and performance advantages that risk stranding hydrogen vehicle infrastructure.
Instead, industrial consumers should use green hydrogen to decarbonize their gray hydrogen consumption for a cheaper, cleaner product.
The IRA’s clean hydrogen production tax credits
The Inflation Reduction Act offers a 10-year production tax credit for “clean hydrogen” production facilities. Incentives begin at $0.60/kg for hydrogen produced in a manner that captures slightly more than half of SMR process carbon emissions, assuming workforce development and wage requirements are met. The PTC’s value rises to $1.00/kg with higher carbon capture rates before jumping to $3.00/kg for hydrogen produced with nearly no emissions.
The carbon capture rate estimates assume an emissions rate of 9.00 kg CO2e / kg H2 from producing gray hydrogen. Permission granted by Energy Innovation Policy and Technology.
However, the IRA’s “clean hydrogen” definition includes upstream emissions, including methane leakage from natural gas pipelines. Since methane is a much more potent greenhouse gas than carbon dioxide, even small leaks significantly increase the carbon capture rate needed to qualify for different PTC tiers.
This suggests “blue” hydrogen produced from pairing SMR and carbon capture and sequestration technology won’t qualify for the highest PTC value. Even hydrogen produced via pyrolysis — which uses natural gas but has no process emissions — may be knocked into lower tiers with enough methane leakage.
Green hydrogen therefore has a $3/kg subsidy advantage over gray and at least a $2/kg advantage over blue. These subsidies will be lower in practice, as the 10-year PTC will be spread over the facilities’ 15-or-more year lifetimes, but they still shift the hydrogen economics paradigm.
The opportunity: Cleaning today’s gray hydrogen while boosting renewable integration
The Inflation Reduction Act makes clean hydrogen production very cheap, but hydrogen faces costs for transportation, storage and conversion to other compounds. The U.S. also lacks hydrogen-compatible pipelines, storage caverns, refueling stations, and equipment like consumer appliances.
The first best use for clean hydrogen is circumventing these mid- and downstream cost and infrastructure challenges. Namely, clean hydrogen can plug-and-play to replace today’s gray hydrogen production.
For example, ammonia facilities and oil refineries use 90% of U.S. annual hydrogen production. Electrolyzers sited nearby can opportunistically produce clean hydrogen to reduce facilities’ fuel costs and emissions.
The gray hydrogen replacement market is huge — 90% of 2021 U.S. utility-scale wind and solar electricity would be required to produce it all via electrolysis. Green hydrogen also has a 25% to 50% greater GHG emissions reduction impact when replacing gray hydrogen than natural gas.
Non-hydro renewables includes wind, solar, biomass, and geothermal. Data excludes distributed generation. Permission granted by Energy Innovation Policy and Technology.
This process can speed renewable energy deployment. Grid-connected electrolyzers can draw from renewables when electricity is cheap, helping finance them for power that would otherwise fetch low prices or be curtailed. When electricity prices rise, electrolyzers can ramp down, allowing the renewables to meet demand and keeping hydrogen production cheap.
The combination is a win-win: grid-connected, price-responsive electrolyzers help clean the industrial sector and power grid without committing to extensive new hydrogen-ready infrastructure and appliances. As U.S. renewables deployment accelerates, the demand for complementary green hydrogen may grow apace, including feeding an enormous clean ammonia export market.
The risk: Misallocating public funds for myopic projects
The Inflation Reduction Act’s clean hydrogen PTC is a massive incentive and can make many potential hydrogen end-uses look attractive. However, these propositions are often a mirage.
Clean hydrogen tax credits will reduce electrolyzer capital costs, helping unsubsidized green hydrogen production costs converge toward the cost of renewable electricity. However, since renewable electricity will always be an input to electrolysis, unsubsidized green hydrogen will never be cheaper than direct use of renewable electricity, even though the $3/kg credit is large enough to temporarily distort the market in hydrogen’s favor. By contrast, renewable energy subsidies are helping unsubsidized wind and solar become cheaper than fossil fuel power plants, as these resources’ costs are independent of each other.
Rightmost chart assumes green hydrogen is used for electricity production ($/MWh), but metaphor extends to any use-case where electricity and hydrogen can compete on the same time-scale. Permission granted by Energy Innovation Policy and Technology.
Despite these dynamics, suddenly cheap hydrogen will amplify the fuel’s hype, inviting proposals for investing in hydrogen infrastructure and compatible end-use equipment. Such actions risk wasting time and money on research or infrastructure that will be underutilized or stranded once Inflation Reduction Act subsidies expire.
For example, gas utility plans to blend hydrogen with natural gas may be cost-effective with the subsidies, but they heighten safety and public health risks and aren’t long-term decarbonization strategies. By comparison, electric appliances like heat pumps and induction stoves use clean electricity approximately four times more efficiently than green hydrogen equivalents.
Other proposals may entail committing public funds to sprawling new infrastructure networks including pipelines and refueling stations to support hydrogen-powered fuel cell vehicles. Yet electric light-duty vehicles hold clear, insurmountable advantages that may be veiled by heavily subsidized hydrogen.
Hydrogen infrastructure proposals will sometimes be worthwhile. For example, geologic caverns for seasonal electricity storage can help clean the last 10% to 20% of the power grid, using green hydrogen to generate electricity when renewables and batteries are unavailable. Hydrogen can also be used as a feedstock or fuel for high-heat industrial processes. But in these cases, hydrogen’s advantage comes from filling a niche that direct electrification cannot, making its inefficiencies irrelevant.
Setting up for success
The IRA’s clean hydrogen tax credits can accelerate a reliable clean electricity transition while beginning to decarbonize industry — if applied judiciously.
Supporting a clean power grid will require incentivizing developers to connect electrolyzers to the grid rather than build standalone projects with co-located renewables, as only the former will allow utilities to benefit from electrolyzers’ flexible demand.
The U.S. Treasury should issue guidance clarifying how electrolytic hydrogen’s carbon intensity will be measured. Its framework should explicitly permit electrolyzers to connect to the grid, using collocated renewables, power purchase agreements, or potentially renewable energy credits to confirm they’re powered by renewables.
Regulators should direct electric utilities to set electrolyzer-specific tariffs, as current industrial tariffs may be mismatched with the flexibility value electrolyzers provide. They should also ease interconnection constraints and build more transmission, both of which can connect co-located renewables and electrolyzer projects to the grid. More grid-connected electrolyzers should then give regulators greater confidence to fast-track utilities’ renewable deployment schedules.
Industry consumers should explore contracts that allow clean hydrogen to replace some or all of their gray hydrogen, reducing costs and providing a cleaner product that may fetch higher prices from climate-conscious purchasers.
However, regulators and policymakers should steel their resolve against temptations to overcommit to hydrogen for end-uses where electrification will ultimately win out.
Research and development should focus on ways clean hydrogen can decarbonize hard-to-electrify sectors like aviation and shipping and boost long-duration electricity storage, rather than focusing on blending hydrogen into natural gas pipelines, using hydrogen for low-heat industrial processes, or designing hydrogen-capable consumer appliances. Limited state funds for commercialization should support electric infrastructure like electric vehicle charging stations and heat pumps, letting private companies take the risk for ventures like hydrogen refueling stations.
Together, these strategies can ensure the Inflation Reduction Act clean hydrogen tax credits maximize their value in reducing GHG emissions without inadvertently leading states and utilities down futile paths.
