Financial Benefits

Could sand be the next lithium?

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By:  Shira Rubin
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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.”

Hubs and spokes: Extending the reach of hydrogen hubs through clean transportation corridors

Posted on by abrahamwien18

Written by: Jonathan Lewis and Anna Menke
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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:  

  1. 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. 
  2. 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.  

Pieces That Need To Fall Into Place To Make Green Hydrogen Viable

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By:  Steven Carlini, VP of Innovation and Data Center
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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.

Diversifying a US$200 billion market: The alternatives to Li-ion batteries for grid-scale energy storage

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By: Oliver Warren
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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% of global 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.

The Inflation Reduction Act upends hydrogen economics with opportunities, pitfalls

Posted on by abrahamwien18

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.

U.S. Inflation Reduction Act: Impacts on Renewable Energy

Posted on by abrahamwien18

New law supports more predictable and consistent policies for solar, wind and other renewable energy and storage developers.


View the original article here

The signing of the U.S. Inflation Reduction Act (IRA) — enacted into law on Aug. 16, 2022 — heralds significant and long-term changes for renewable energy development and energy storage installations. The new law represents the single largest climate-related investment by the U.S. government to date, allocating $369 billion (USD) for energy and climate initiatives to help transition the U.S. economy toward more sustainable energy resources.

According to industry estimates, the IRA stands to more than triple U.S. clean energy production, which would result in about 40% of the country’s energy coming from renewable sources such as wind, solar and energy storage by 2030. This would mean an additional 550 gigawatts of electricity generated via renewable sources in less than 10 years.

The IRA’s expected impacts present significant opportunities for renewable energy developers and energy storage companies. Below, we discuss the law’s key effects on the renewable and storage industries, with a special focus on critical technology, software and advisory support for companies launching or expanding their renewable energy projects as the new law takes effect.

More reliable tax credit structures likely to transform renewable energy development

Crucially, the IRA establishes long-term energy tax credit structures to support renewable energy development, giving companies a more stable 10-year window for such incentives versus the previous on-again, off-again incentives that drove “boom and bust” cycles of renewables projects.

Renewables industry trade group American Clean Power reports that for the second quarter of 2022, more than 32 gigawatts of renewable energy projects were delayed, and new project development and installations also fell to their lowest levels since 2019. The group attributes these slumping performance statistics to uncertainty in tax and incentive policies along with transmission challenges and trade restrictions; provisions of the IRA may help reverse this performance trajectory.

“Historically, the U.S. renewables industry has relied on tax credits that required reauthorization from Congress every few years, which created boom-bust cycles and significant challenges in terms of planning for long-term growth,” explained Gillian Howard, global director of sustainable energy and infrastructure at UL Solutions. She added that the IRA establishes a 10-year policy in terms of tax credits for wind, solar and energy storage projects. The new law also provides incentives for green hydrogen, carbon capture, U.S. domestic energy manufacturing and transmission, Howard noted.

“We expect the IRA to both significantly accelerate and increase the deployment of new renewable energy projects in the U.S. over the next decade,” Howard says. “This will be transformational.”

Standalone storage now eligible for tax credits: a long-awaited change and major IRA impact

The use of energy storage has taken on added urgency in recent years as extreme weather and geopolitical issues increasingly challenge energy access and reliability. Projects for energy storage, including batteries and thermal and mechanical storage, have previously been included in investment tax credit programs. Now the IRA extends tax credits for energy storage through 2032. The new law also opens tax credit eligibility to standalone energy storage, which entails storage units constructed and operated independently of larger energy grids.

“Providing an investment tax credit for standalone storage is the single-most important policy change in the IRA — period,” said David Mintzer, energy storage director at UL Solutions. “This one change sets up all of the other energy storage advantages gained from the new law. Those of us in the BESS industry have been waiting for this to happen for more than 10 years, and this is the most significant legislation to accelerate the transition to clean energy and smart grids.”

Mintzer noted that the IRA allows placement of battery energy storage systems (BESSs) where energy demand is highest and removes longstanding requirements that storage systems must be paired to solar sources. Accordingly, key impacts of the new law on energy storage projects in the U.S. will likely include the following near-term impacts:

  • Standalone utilities – The IRA provides more substantial economic incentives for more sites (nodes) that connect to grid networks in support of wholesale energy and additional dispatch services.
  • Standalone distributed generation – More flexible placement of standalone BESSs can support economic arguments for commercial development at sites with inadequate access to larger energy grids.
  • Storage technologies – The IRA’s tax credit provisions for standalone energy storage will prompt research and development and, ultimately, the execution of more and different types of batteries.
  • Banking – Smaller banks and lending organizations may be more likely to finance the construction and development of smaller energy storage systems versus larger and costlier main-grid projects.

“This decoupling of the storage-solar rules will enable BESS sites to be placed where they can provide the best economic returns,” Mintzer explained, adding that battery use will also become more flexible to better support energy grids. Ultimately, Mintzer said, developing and deploying more storage systems will help the U.S. achieve its clean energy goals.

Solar provisions: PTC versus ITC

The IRA includes provisions for 100% production tax credits (PTC) for solar, which transitions to a technology-neutral PTC in 2025. Until the passage of the IRA, solar developers could use the investment tax credit (ITC), which was originally set at 30% of eligible project costs, stepping down over the last few years to 26%, 22% and 0%. The IRA reset the ITC to 30% and provides an option for developers to opt for the PTC instead of the ITC. Rubin Sidhu, director of solar advisory services at UL Solutions, said, “Preliminary analysis shows that for projects with a high net capacity factor (NCF), PTC may be a more favorable option. Further, as solar equipment costs continue to decrease and NCFs continue to go up with better technology, PTC will be more favorable compared to ITC for more and more projects.”

Since the PTC is tied to actual energy generation by a project over 10 years, we expect the investors will be more sensitive to the accuracy of pre-construction solar resource and energy estimates, as well as the ongoing performance of projects.

Tools to support renewable energy development and storage in the IRA era

Launching renewable energy development and storage projects under the auspices of the IRA will require robust tools and technologies in order to manage these projects’ technical, operational and financial components in what may well become a more highly competitive and crowded field.

The degree to which a renewable energy developer will require third-party technologies and advisory partnerships will depend on the firm’s internal resources and commercial goals. Our experience at UL Solutions assessing more than 300 gigawatts worth of renewable energy projects has been that some firms require tools to evaluate and design projects themselves, while other companies seek full-project advisory support. To accommodate a diverse array of technology and advisory needs across the industry, UL Solutions has developed products and services, including:

  • Full energy and asset advisory services.
  • Due diligence support.
  • Testing and certification.
  • Software applications for solar, wind, offshore wind and energy storage projects.

Effective tools for early-stage feasibility and pre-construction assessments are crucial for the long-term viability of renewable energy development projects. UL Solutions provides modeling and optimizing tools for hybrid power projects via our Hybrid Optimization Model for Multiple Energy Resources (HOMER®) line of software, including HOMER Front for technical and economic analysis of utility-scale standalone and hybrid energy systems, HOMER Grid for cost reduction and risk management for grid-connected energy systems, and HOMER Pro for optimizing microgrid design in remote, standalone applications. UL Solutions also supports wind energy assessment projects with our Windnavigator platform for site prospecting and feasibility assessments, Windographer software for wind data analytics and visualization support, and Openwind wind farm modeling and layout design software.

For energy storage system developers, HOMER Front also features tools to design and evaluate battery augmentation plans as well as dispatch strategies, applicable when participating in merchant energy markets or contracting with power purchase agreements.

Conclusion: Reliable tools for a new frontier

Given the magnitude and scope of the IRA, it will take some time for regulatory implementation to play out. Effects of the new law will not be immediate. Over time, the IRA will provide more predictability and certainty in terms of tax credits and related incentives for renewable energy development and lays the groundwork for innovation and expansion of energy storage systems and technologies. Gaining a competitive advantage in this new era for renewables, nonetheless, will require the right software capabilities, third-party advisory support or both, depending on companies’ resources and commercial objectives.

Is Green Hydrogen Energy of the Future?

Posted on by abrahamwien18

By: Jennifer L
View the original article here

The global energy market has become even more unstable and uncertain. Add to this the challenges caused by climate change. To meet future demand, sustainable and affordable energy supplies are a must, raising a question “is green hydrogen energy of the future?”

Recently, hydrogen is leading the debate on clean energy transitions. It has been present at industrial scale worldwide, offering a lot of uses but more so in powering things around us.

In the U.S., hydrogen is used by industry for refining petroleum, treating metals, making fertilizers, as well as processing foods.

Petroleum refineries use it to lower the sulfur content of fuels. NASA has also been using liquid hydrogen since the 1950s as a rocket fuel to explore outer space.

This warrants the question: is green hydrogen the energy of the future?

This article will answer the question by discussing hydrogen and its uses, ways of producing it, its different types, and how to make green hydrogen affordable.

Using Hydrogen to Power Things

Hydrogen (H2) is used in a variety of ways to power things up.

Hydrogen fuel cells produce electricity. It reacts with oxygen across an electrochemical cell similar to how a battery works to generate electricity.

But this also produces small amounts of heat and water.

Hydrogen fuel cells are available for various applications.

The small ones can power laptops and cell phones while the large ones can supply power to electric grids, provide emergency power in buildings, and supply electricity to off-grid places.

Burning hydrogen as a power plant fuel is also gaining traction in the U.S. Some plants decided to run on a natural gas-hydrogen fuel mixture in combustion gas turbines.

Examples are the Long Ridge Energy Generation Project in Ohio and the Intermountain Power Agency in Utah.

Finally, there’s also a growing interest in hydrogen use to run vessels. The Energy Policy Act of 1992 considers it an alternative transportation fuel because of its ability to power fuel cells in zero-emission vessels.

A fuel cell can be 2 – 3 times more efficient than an internal combustion engine running on gasoline. Plus, hydrogen can also fuel internal combustion engines.

  • Hydrogen can power cars, supply electricity, and heat homes.

Once produced, H2 generates power in a fuel cell and this emits only water and warm air. Thus, it holds promise for growth in the energy sector.

  • The IEA calculates that hydrogen demand has tripled since the 1970s and projects its continued growth. The volume grew to ~70 million tonnes in 2018 – an increase of 300%.

Such growing demand is due to the need for ammonia and refining activities.

Producing hydrogen is possible using different processes and we’re going to explain the three popular ones.

3 Ways to Produce Hydrogen

The Fischer-Tropsch Process:

The commonly used method in producing hydrogen today is the Fischer-Tropsch (FT) process. Most hydrogen produced in the U.S. (95%) is made this way.

This process converts a mixture of gasses (syngas) into liquid hydrocarbons using a catalyst at the temperature range of 150°C – 300°C

In a typical FT application, coal, natural gas, or biomass produces carbon monoxide and hydrogen – the feedstock for FT. This process step is known as “gasification”.

Under the step called the “water-gas shift reaction”, carbon monoxide reacts with steam through a catalyst. This, in turn, produces CO2 and more H2.

In the last process known as “pressure-swing adsorption”, impurities like CO2 are removed from the gas stream. This then leaves only pure hydrogen.

The FT process is endothermic, which means heat is essential to enable the necessary reaction.

The Haber-Bosch Process:

The Haber-Bosch process is also called the Haber ammonia process. It combines nitrogen (N) from the air with hydrogen from natural gas to make ammonia.

The process works under extremely high pressures and moderately high temperatures to force a chemical reaction.

It also uses a catalyst mostly made of iron with a temperature of over 400°C and a pressure of around 200 atmospheres to fix N and H2 together.

The elements then move out of the catalyst and into industrial reactors where they’re eventually converted into ammonia.

But hydrogen can be obtained onsite through methane steam reforming in combination with the water-gas shift reaction. This step is the same as the FT process, but the input is not carbon but nitrogen.

Both the FT and Haber-Bosch are catalytic processes. It means they require high-temperature and high-pressure reactors to produce H2.

While these two methods are proven technologies, they still emit planet-warming CO2. And that’s because most of the current hydrogen production (115 million tonnes) burns fossil fuels as seen in the chart below.

76% of the hydrogen comes from natural gas and 23% stems from coal. Only ~2% of global hydrogen production is from renewable sources.

This present production emits about 830 million tonnes of CO2 each year.

Thus, the need to shift to a sustainable input and production method is evident. This brings us to a modern, advanced way to produce low-carbon hydrogen or green hydrogen.

The Water Electrolysis Method:

With water as an input, hydrogen features both high efficiency in energy conversion and zero pollution as it emits only water as a byproduct.

That’s possible through the water electrolysis method. It’s a promising pathway to achieve efficiently and zero emission H2 production.

Unlike the FT and Haber-Bosch processes, water electrolysis doesn’t involve CO2.

Instead, it involves the decomposition of water (H2O) into its basic components – hydrogen (H2) and oxygen (O2) via passing electric current. Hence, it’s also referred to as the water-splitting electrolysis method.

Water is the ideal source as it only produces oxygen as a byproduct.

As shown in the figure above, solar energy is used for decomposing water. Then electrolysis converts the stored electrical energy into chemical energy through the catalyst.

The newly created chemical energy can then be used as fuel or transformed back into electricity when needed.

The hydrogen produced via water electrolysis using a renewable source is called green hydrogen, which is touted as the energy for the future.

But there are two other types of hydrogen, distinguished in color labels – blue and grey.

3 Types of Hydrogen: Grey, Blue, and Green

Though the produced H2 have the same molecules, the source of producing it varies.

And so, the different ‘labels’ of hydrogen represented by the three colors reflect the various ways of producing H2.

Processes that use fossil fuels, and thus emit CO2, without utilizing CCS (Carbon Capture & Storage) technology produce grey hydrogen. This type of H2 is the most common available today.

Both FT and Haber-Bosch processes produce grey hydrogen from natural gas like methane without using CCS. Steam methane reforming process is an example.

  • Under the grey hydrogen label are two other colors – brown (using brown coal or lignite) and black (using black coal)

On the other hand, blue hydrogen uses the same process as grey. However, the carbon emitted is captured and stored, making it an eco-friendly option.

But producing blue H2 comes with technical challenges and more costs to deploy CCS. There’s a need for a pipeline to transport the captured CO2 and store it underground.

What makes green hydrogen the most desirable choice for the future is that it’s processed using a low carbon or renewable energy source. Examples are solar, wind, hydropower, and nuclear.

The water electrolysis method is a perfect example of a process that creates green H2.

In a gist, here’s how the three types of hydrogen differ in terms of input (feedstock) and byproduct, as well as their projected costs per kg of production.

Since the process and the byproduct of producing green hydrogen don’t emit CO2, it’s seen as the energy of the future for the world to hit net zero emissions.

That means doing away with fossil fuels or avoiding carbon-intensive processes. And green H2 promises both scenarios.

But the biggest challenge with this green hydrogen is the cost of scaling it up to make it affordable to produce.

Pathways toward Green Hydrogen as the Energy of Future

As projected in the chart above, shifting from grey to green H2 will not likely happen at scale before the 2030s.

The following chart also shows current projections of green hydrogen displacing the blue one.

The projections show an exponential growth for H2. What we can think out of this is that green hydrogen will take a central role in the future global energy mix.

  • While it’s technically feasible, cost-competitiveness of green H2 becomes a precondition for its scale up.

Cheap coal and natural gas are readily available. In fact, producing grey hydrogen can go as low as only US$1/kg for regions with low gas or coal prices such as North America, Russia, and the Middle East.

Estimates claim that’s likely the case until at least 2030. Beyond this period, stricter carbon pricing is necessary to promote the development of green H2.

According to a study, blue hydrogen can’t be cost competitive with natural gas without a carbon price. That is due to the efficiency loss in converting natural gas to hydrogen.

In the meantime, the cost of green hydrogen from water electrolysis is more expensive than both grey and blue.

  • Estimates show it to be in the range of US$2.5 – US$6/kg of H2.

That’s in the near-term but taking a long-term perspective towards 2050, innovations and scale-up can help close the gap in the costs of hydrogen.

For instance, the 10x increase in the average unit size of new electrolyzers used in water electrolysis is a sign of progress in scaling up this method.

Estimates show that the cost of green H2 made through water electrolysis will fall below the cost of blue H2 by 2050.

More importantly, while capital expenditure (CAPEX) will decline, operation expenditure (OPEX) such as fuel is the biggest chunk of producing green hydrogen.

  • Fuel accounts for about 45% – 75% of the production costs.

And the availability of renewable energy sources affects fuel cost, which is the limiting factor right now.

But the decreasing costs for solar and wind generation may result in low-cost supply for green H2. Technology improvements also boost efficiency of electrolyzers.

Plus, as investments in these renewables continue to grow, so does the chance for a lower fuel cost for making green H2.

  • All these increase the commercial viability of green hydrogen production.

While these pathways are crucial for making green hydrogen, the grey and blue hydrogen productions do still have an important role to play.

They can help develop a global supply chain that enables the sustainability and eventuality of green H2.

When it comes to the current flow of capital in the industry, there have been huge investments made into it.

Investments to Scale Up Green H2 Production

Fulfilling the forecast that green hydrogen will be the energy of the future requires not just billions but trillions of dollars by 2050 – about $15 trillion. It means $800 billion of investments per year.

That’s a lot of money! But that’s not impossible with the amount of capital available in the sector today.

Major oil companies have plans to make huge investments that would make green H2 a serious business.

For instance, India’s fastest-growing diversified business portfolio Adani and French oil major TotalEnergies partnered to invest more than $50 billion over the next 10 years to build a green H2 ecosystem.

An initial investment of $5 billion will develop 4 GW of wind and solar capacity. The energy from these sources will power electrolyzers.

Also, there’s another $36 billion investment in the Asian Renewable Energy Hub led by BP Plc. It’s a project that will build solar and wind farms in Western Australia.

The electricity produced will be used to split water molecules into H2 and O2, generating over a million tons of green H2 each year.

Other large oil firms will follow suit such as Shell. The oil giant decided to also invest in the sector. It’s building the Holland Hydrogen I that’s touted to be Europe’s biggest renewable hydrogen plant.

Green Hydrogen as the Energy of the Future

If the current projections of green hydrogen become a reality, it has the potential to be the key investment for the energy transition.

Geothermal energy could be off-ramp for Texas oil

Posted on by abrahamwien18

By: Saul Elbein
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AUSTIN, Texas — Four years of drilling for energy deep underground would be enough to build Texas a carbon-free state electric grid, a new study by an alliance of state universities has found. 

The state’s flagship universities — including the University of Texas at Austin, Rice University and Texas A&M University — collaborated with the International Energy Agency to produce the landmark report.  

It depicts the Texas geothermal industry as a potential partner to the state’s enormous oil and gas sector — or an ultimate escape hatch.  

In the best case, the industry represents “an accelerating trend” that could replicate — or surpass — the fracking boom, said Jamie Beard of the Texas Geothermal Entrepreneurship Organization at the University of Texas.

“Instead of aiming for a 2050 moonshot that we have to achieve some scientific breakthrough for — geothermal is deployable now,” Beard said. “We can be building power plants now.”

The authors stressed that the geothermal, oil and gas industries all rely on the same fundamental skillset — interpreting Texas’s unique geology to find valuable underground liquids.  

In this case, however, the liquid in question had long been seen as a waste product: superheated water released as drillers sought oil and gas.   

About “44 terawatts of energy flow continually out of the earth and into space,” said Ken Wisan, an economic geologist at the University of Texas.

“Rock is a great heat battery, and the upper 10 miles of the core holds an estimated 1,000 years’ worth of our energy needs in the form of stored energy,” Wisan added. 

Most of the state’s population lives above potentially usable geothermal heat — as long as there’s a will to drill deep enough.  

Superheated trapped steam that is nearly 300 degrees Fahrenheit — the sweet spot for modern geothermal — is accessible about three to five miles below the state capital of Austin and 2 1/2 to 3 miles beneath its most prominent city of Houston, the report found. 

The report casts geothermal energy as a possible way out of two energy paradoxes. 

The first concerns the state’s beleaguered electric grid. The isolated system has been repeatedly driven nearly to the point of blackouts by extreme heat and cold, as well as the relentless, demanding growth of the state population. 

According to the Energy Information Agency, the state’s substantial renewable potential is meeting part of this growth: Texas leads the nation in wind energy and has near-leading solar potential.  

But the Republican-dominated legislature has been anxious over how to establish “baseload” power — the minimum demand of the grid — as well as readily “dispatchable” energy resources. 

Several state Republican leaders and the state Public Utility Commission have pushed for the construction of new coal, natural gas and nuclear plants to provide round-the-clock power.

Despite their different forms, these “thermal” options rely on the same fundamental trick. Whether powered by coal or uranium, most modern power plants use the fuel boiling water to create steam, which spins an electromagnetic turbine, creating an electric current. 

Geothermal offers another cheaper and more climate-friendly solution: start with steam, which exists in superheated pockets miles below the earth’s surface. 

Rebuilding the state a power system on a base of geothermal energy would give “the same performance as gas, coal or nuclear” at a lower cost, said Michael Webber, a professor of clean energy at the University of Texas. 

But Webber said it would also do so “without the same fuel reliability problems.”

During Texas’s February 2021 winter storm, Webber noted, natural gas and coal supplies froze — which wouldn’t have been a problem with geothermal.  

The industry also gives Texas a means of transitioning its flagship industry off planet-heating products like oil and gas. 

The International Energy Agency declared in May 2021 that for the world to meet global climate goals, new oil and gas production would have to cease, as The Hill reported. 

Since that warning, global oil and gas production has continued to increase — and is on track to hit record levels in 2023. But Tuesday’s report, which the global energy watchdog helped produce, suggested that geothermal energy could be a politically palatable offramp for the industry.  

The report found that if the Texas drilling industry drilled as many geothermal wells as it currently does oil and gas, about 15,000 per year, the state could run itself off geothermal power by 2027.

Webber said that would free up natural gas to replace more carbon-intensive coal in other locations, from Indiana and West Virginia to India and China.

With Texas’s needs at home met by cheap geothermal, “oil and gas would have more molecules to sell to other people probably for more money,” Webber added.

Beard said that the oil and gas industry offers a potential model for how the geothermal industry could rapidly expand

“The very beginnings of oil and gas, they were picking up oil and gas off the surface of the ground and puddles,” she said, in an analogy to the geothermal industries in highly geologically active Iceland, with its frequent eruptions. 

But eventually, the fossil fuel industry began to drill and advance. “And then sure enough, now we’re drilling in 5,000 feet of water offshore with billion-dollar, technically complex wells,” Beard said. 

“And that is what we could do for geothermal, right?” she said. “We could go for the deepwater of geothermal, and we can do it in the next few decades.

Artificial Intelligence in battery energy storage systems can keep the power on 24/7

Posted on by abrahamwien18

By: Carlos Nieto, Global Product Line Manager, Energy Storage at ABB
View the original article here

When partnered with Artificial Intelligence (AI), the next generation of battery energy storage systems (BESS) will give rise to radical new opportunities in power optimisation and predictive maintenance for all types of mission-critical facilities.

Undeniably, large-scale energy storage is shaping variable generation and supporting changing demand as part of the rapid decarbonisation of the energy sector. But this is just the beginning.

Here, Carlos Nieto, Global Product Line Manager, Energy Storage at ABB, describes the advances in innovation that have brought AI-enabled BESS to the market, and explains how AI has the potential to make renewable assets and storage more reliable and, in turn, more lucrative.

It is no surprise that more industrial and commercial businesses are embracing green practices in a big way. With almost a quarter (24.2%) of global energy use attributed to industry, its rapid decarbonization is a critical component of our net zero future and remains the subject of new sustainable standards and government regulations across the world.

Adding further pressure is an increasingly eco-conscious consumer, demanding the companies they spend with go the extra mile to be as environmentally friendly as possible. This is seen in a recent analysis of the stock market which revealed a direct link between pro-sustainability activity and positive stock prices impact.

More than ever though, going greener isn’t just about ticking the environmental, social, and governance (ESG) boxes, but an issue of energy security. For years, traditional fossil-based systems of energy production and consumption – including oil and gas – have become increasingly expensive.

Add to that the current energy crisis, and businesses now face historic energy price highs not seen since the early 70s and widespread supply issues. For energy-intensive industrial and commercial premises where continuous power supply is often mission critical, this places an even greater onus on sustainability to mitigate the risks of escalating fuel prices and market volatility.

The result is a profound shift in the energy landscape, as more companies move away from the entrenched centrally run energy model and transition to self-generation for a more sustainable and secure future.

Decarbonization, decentralization and digitalization: Benefits and challenges

As with most aspects of the highly complex energy category, this transition is not necessarily a simple one.

To understand why, we must first consider what are widely established as the key drivers of this change – decarbonization, decentralization, and digitalization. While they each bring their own set of benefits, they also bring challenges too.

In terms of decarbonization, global industry continues to make progress toward reducing emissions and, in turn energy costs, by ramping up the pace and scale of renewable investments. But, while this shows progress, the reality is that the inherent variability of wind and solar poses some limitations.

Solar, for example, will only generate electricity in line with how much sunshine there is and will not match the same profile of the electricity that a site is using. Used in silo, companies are left with having to top-up with electricity from the grid or waste any excess generated.

Adding further complexity is the opportunity for decentralization. The decentralized nature of renewable generation holds the potential for power users to not only produce much of the electricity they need locally, but to transition to an independent energy system, such as a microgrid, for the ultimate in self-sufficiency.

One of the major benefits of a microgrid is that it can act as part of the wider grid while also being able to disconnect from it and operate independently, for example, in the event of a blackout. Of course, this presents a huge advantage for mission critical applications, where even a moment’s downtime can entail huge operational and financial implications.

But this also brings challenges. Although a decentralized approach makes for a more resilient and secure system, it must be carefully ‘synced’ to ensure stability and alignment between generation and demand, and the wider central network.

Achieving this and meeting decarbonization goals requires digitalization. This will lead to a shift towards advanced energy management software which allows real-time automated communication and operation of energy systems. Such software will allow businesses to optimize the generation, supply, and storage of renewable generation according to their requirements, the market and other external factors.

In the future, it is predicted that companies could even go beyond self-sufficiency and leverage a lucrative new revenue stream by reselling excess generation, not just back to utilities but even direct to consumers or other businesses.

But for now, we need to focus on what the most suitable framework is for delivering this new layer of next-generation intelligence for the evolving energy system.

Artificial Intelligence can take BESS to a new level of smart operation

The answer to this and many of the other key challenges facing this energy transition lies in BESS.

‘Behind-the-meter’ BESS solutions already form a central part of decarbonization strategies, enabling businesses to store excess energy and redeploy it as needed for seamless renewable integration.

When partnered with an energy management system (EMS), monitoring and diagnostics, the BESS allows operators to optimize power production by leveraging peak shaving, load-lifting, and maximizing self-consumption.

Another big advantage is that these systems can provide critical backup power, preventing potential revenue losses due to production delays and downtime. But there’s more.

Beyond tackling decarbonization, applying Artificial Intelligence (AI) takes BESS to a completely new level of smart operation.

As many operatives will know, energy storage operations can be complex. They typically involve constant monitoring of everything, from the BESS status, solar and wind outputs through to weather conditions and seasonality. Add to that the need to make decisions about when to charge and discharge the BESS in real-time, and the result can be challenging for human operators.

By introducing state-of-the art AI, we can now achieve all of this in real-time, around-the-clock for a much more effective and efficient energy storage operation.

This unique innovation takes a four-pronged approach: data acquisition, prediction, simulation, and optimization. Using advanced machine learning, the system is able to constantly handle, analyze and exploit data.

This data insight is partnered with wider weather, seasonality and market intelligence to forecast future supply and demand expectations. As a final step, a simulation quantifies how closely the predictions resemble the real physical measures to provide further validation.

The result is radical new potential for energy and asset optimization. Through predictive analytics, it will allow commercial and industrial operators to save and distribute self-generated resources more effectively and better prepare for upcoming demand. It can also ensure ‘business as usual’ in the ability to identify and address issues before they escalate and anticipate similar failures or performance constraints.

Greater intelligence is incorporated throughout the system, which allows operators to understand everything from the resting state of charge to the depth of discharge and how these factors can degrade the battery over time. This intelligence makes it easier to predict wear and tear, increases overall lifespan and ultimately the return on the investment for the end user.

There is no doubt that the energy transition is on, as decarbonization, decentralization and digitalization continue to redefine everything we thought we already knew about how to produce and consume energy.

While this brings new complexity for industrial and commercial operators, it also provides an opportunity to reimagine environmental strategy and take advantage of innovation.

With benefits that include significant energy reductions, asset optimization and mission-critical reliability, the transition to AI-enabled BESS is an inevitable and intelligent one.

A faster energy transition could mean trillions of dollars in savings

Posted on by abrahamwien18

Decarbonization may not come with economic costs, but with savings, per a recent paper.

By Grace Donnelly
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If forecasters predicting future costs of renewable energy were contestants on The Price Is Right, no one would be making it onstage.

Projections about the price of technologies like wind and solar have consistently been too high, leading to a perception that moving away from fossil fuels will come at an economic cost, according to a recent paper published in Joule.

“The narrative that clean energy and the energy transition are expensive and will be expensive—this narrative is deeply embedded in society,” Rupert Way, a study coauthor and postdoctoral researcher at the University of Oxford’s Institute for New Economic Thinking and at the Smith School of Enterprise and the Environment, told Emerging Tech Brew. “For the last 20 years, models have been showing that solar will be expensive well into the future, but it’s not right.”

The study found that a rapid transition to renewable energy is likely to result in trillions of dollars in net savings through 2070, and a global energy system that still relies as heavily on fossil fuels as we do today could cost ~$500 billion more to operate each year than a system generating electricity from mostly renewable sources.

Way said the authors were ultimately trying to start a conversation based on empirically grounded pathways, assuming that cost reductions for these technologies will continue at similar rates as they have in the past.

“Then you get this result that a rapid transition is cheapest. Because the faster you do it, the quicker you get all those savings feeding throughout the economy. It kind of feels like there’s this big misunderstanding and we need to change the narrative,” he said.

Expectation versus reality

Out of 2,905 projections from 2010 to 2020 that used various forecasting models, none predicted that solar costs would fall by more than 6% annually, even in the most aggressive scenarios for technological advancement and deployment. During this period, solar costs actually dropped by 15% per year, according to the paper.

The Joule paper took historical price data like this—but across renewable energy tech beyond just solar, including wind, batteries, and electrolyzers—and paired it with Wright’s Law. Also known as the “learning curve,” the law says costs will decline by a certain percentage as effort and investment in a given technology increase. In 2013, an analysis of historical price data for more than 60 technologies by researchers at MIT found that Wright’s Law most closely resembled real-world cost declines.

The researchers used this method to determine the combined cost of the entire energy system under three scenarios over time: A fast transition, in which fossil fuels are largely eliminated around 2050; a slow transition, in which fossil fuels are eliminated by about 2070; and no transition, in which fossil fuels continue to be dominant.

The team found that by quickly replacing fossil fuels with less expensive renewable tech, the projected cost for the total energy system in the fast-transition scenario in 2050 is ~$514 billion less than in the no-transition scenario.

And while the cost of solar, wind, and batteries has dropped exponentially for several decades, the prices of fossil fuels like coal, oil, and gas, when adjusted for inflation, are about the same as they were 140 years ago, the researchers found.

“These clean energy techs are falling rapidly in cost, and fossil fuels are not. Currently, they’re just going up,” Way said.

Renewable energy is not only getting less expensive much faster than expected, but deployments are outpacing forecasts as well. More than 20% of the electricity in the US last year came from renewables, and 87 countries now generate at least 5% of their electricity from wind and solar, according to the paper—a historical tipping point for adoption.

Even in its slowest energy-transition scenario, the International Energy Agency forecasts that global fossil-fuel consumption will begin to fall before 2030, according to a report released last week.

Way and the Oxford team found that a fast transition to renewable energy could amount to net savings of as much as $12 trillion compared with no transition through 2070.

The paper didn’t account for the potential costs of pollution and climate damage from continued fossil-fuel use in its calculations.

“If you were to do that, then you’d find that it’s probably hundreds of trillions of dollars cheaper to do a fast transition,” Way said.

Policy and investment decisions about how quickly to transition away from fossil fuels often weigh the long-term benefits against the present costs. But what this paper shows, Way said, is that a rapid transition is the most affordable regardless.

“It doesn’t matter whether you value the future a lot, or a little, you still should proceed with a fast transition,” he said. “Because clean energy costs are so low now, and they’re likely to be in the future, we can justify doing this transition on economic grounds, either way.”