By Joseph Webster and William Tobin View the original article here
Long-haul trucking is a highly promising use case for the US hydrogen industry, and California and Texas are two large potential markets for pioneering hydrogen-fueled trucking. Both states have excellent green hydrogen potential and are taking initial steps to become hydrogen trucking hubs. When it comes to decarbonizing heavy-duty transportation, hydrogen is here for the long-haul.
Cleaning up hydrogen
Today, the vast majority of hydrogen is produced from reforming the methane in coal or natural gas in a process that produces ten times more carbon dioxide than hydrogen by mass. It is principally used for refining heavy sour oil and producing ammonia for fertilizer.
The most promising pathways to create zero-carbon clean hydrogen at scale are through renewables-produced green hydrogen or nuclear-powered pink hydrogen, both of which use zero-carbon electricity to separate hydrogen and oxygen via electrolysis. There is also blue hydrogen, which comes from natural gas in a process paired with carbon capture. Blue hydrogen’s role in decarbonization, however, is contingent on the mass buildout of carbon transportation and storage infrastructure.
If deployed judiciously, clean hydrogen can have a meaningful impact on lowering emissions in hard-to-electrify sectors, which require a chemical feedstock, long-duration energy storage, or extreme heat.
Long-haul trucking is a viable clean hydrogen offtaker
For most forms of transportation, growing economies of scale have given batteries an edge over hydrogen fuel cells. However, long-haul trucking—which accounts for 7 percent of transportation emissions—may be too high a fence for batteries to climb.
As a vehicle becomes heavier, its battery must expand proportionately in volume to provide the requisite power. Electric freight tractors use battery packs that are significantly heavier than the weight of diesel a truck typically carries, which decreases range and payload capacity while requiring more frequent charging. This is meaningful in the freight industry, where time is precious, and downtime can come at a cost of over $50 per hour before accounting for costs of charging. An electric long-haul truck takes thirty minutes to charge to only 70 percent capacity even with megawatt charging. In comparison, hydrogen re-fueling can be done quickly. Refueling a hydrogen truck takes ten minutes.
Hydrogen fuel cell trucks are therefore likely to edge out batteries for trips surpassing 180 miles and payloads above 24,000 pounds, according to an industry study.
The US Department of Energy estimates that total cost of ownership for hydrogen fuel cell long-haul vehicles will become affordable by 2030 thanks to new production tax credits for clean hydrogen. Furthermore, the department cites evidence that the long-haul trucking sector is willing to pay a premium for clean hydrogen. This outcome, however, is contingent on a buildout of refueling infrastructure along freight corridors. To boost demand, infrastructure could be built along freight lines that support high volumes of freight, such as near seaports. This can help medium-sized refueling stations reach their breakeven utilization rate. To do so, industry and policymakers must overcome a chicken-and-egg problem. The development of refueling infrastructure is critical to enable hydrogen-powered long-haul trucks, and—conversely—hydrogen refueling stations will rely on long-haul trucking for their income, as hydrogen uptake in transportation is likely to be confined to this sector.
California and Texas: Unlikely hydrogen trucking partners
California and Texas are important players in both green hydrogen and long-haul trucking.
Not only do the two states have the largest populations and economies in the country, but they also have outstanding green hydrogen potential.
Both California and Texas have excellent renewable resources, including solar and wind. The two states have deployed nearly 74 gigawatts of solar and wind capacity with another 36 GW in development.
Texas and California are the nation’s largest and second-largest renewables generators. As more renewable electricity production grows in these states, so will green hydrogen capacity—although there will be tensions between providing renewables for power generation or hydrogen.
Long-haul trucking is a natural use case for green hydrogen in both states. Texas and California are the country’s largest users of diesel for the transportation sector, consuming 633,000 barrels per day in 2021, or about 21 percent of total US diesel demand. Both states rely heavily on trucking to transport cargo from ports along the coast of California and Texas to destinations further inland. Indeed, Los Angeles, Long Beach, and Houston are the country’s first, second, and fifth-largest container ports by volume, respectively.
There is already evidence that Texas and California’s long-haul trucking sectors could see synergies between ports and green hydrogen production. California provides fiscal support for zero-emissions vehicles, plans to end the sale of fossil fuel-powered medium- and heavy-duty trucks by 2036, and continues to develop hydrogen refueling infrastructure. Tellingly, Hyundai Motor will soon operate thirty fuel cell electric trucks in California; Hyundai states this deployment will mark the largest commercial deployment of fuel cell electric trucks in the United States in the super-large vehicle class. In North Texas, Air Products and AES are teaming up to construct the country’s largest green hydrogen facility to service the trucking industry.
The trucking fleet is replaced very rapidly: the average lifespan of a super-large class truck is eight years, while the median truck on the road today is approximately six years old. In comparison, personal vehicles are replaced on average only every ten and a half years. Moreover, unlike the personal vehicle segment, most long-haul trucks are procured by fleet owners who pay very close attention to the total cost of ownership, not just the sticker price. If hydrogen-fuel trucks become more competitive than their diesel counterparts, there could be a relatively rapid adjustment.
Hydrogen: Here for the long-haul
Hydrogen’s technical and economic fundamentals are likely to improve as technology advances and the Inflation Reduction Act incentivizes investments in renewables. Owing to their renewables potential, large ports, and significant diesel demand, California and Texas are primed to lead the trucking market’s transformation. While trucking fleet turnover will take time, hydrogen appears poised to disrupt the US trucking market.
By: Steven Carlini, VP of Innovation and Data Center View the original article here
In the zero-carbon economy of the future, electricity will become the dominant energy but green hydrogen (and the fuels derived from it) will have a role to play as well. Making green hydrogen viable and abundant will take collaboration, effort, and investment.
Pieces that need to fall into place to make green hydrogen viable
Hydrogen definitely has a role to play in global decarbonization. In the decarbonized world of the future, electricity will become the dominant energy with a 60-70% share in 2050, biofuels will rise, dependence on fossil-based energy will significantly decrease and hydrogen will increase. I want to focus on green hydrogen – derived from water using electrolysis since it is the most promising. In my estimation, green hydrogen will rise between 3 – 10 times the 90 Mt of hydrogen used today by 2050. The 3X – 10X projection goes from a very conservative 270 Mt (3X) to an aggressive 900 Mt (10X). So why is there such a large gap if green hydrogen is the energy source needed for hard-to-abate applications? Mainly because there are 10 significant “pieces” of the puzzle that must come together to produce green hydrogen at the scale needed.
1) Renewable Generation Electricity Capacity – Green hydrogen must be derived through electrolysis which is highly energy intensive. For hydrogen to be green the process must be electrified using a sustainable source (hydro, wind, or solar). How much? The electricity required by 2050 for decarbonized electrification and green hydrogen production of 900 Mt (10X) is estimated to be 130,000 TWh – around 5X today’s total electrical supply of 27,000 TWh. By 2050 using the 900 Mt (10X) green H2 assumption, 30% of electricity use will be dedicated to producing clean hydrogen and its derivatives, such as e-ammonia and e-methanol.
2) Electrolyzer Capacity – Once there is sufficient renewable generation, the capacity of electrolyzer plants needs to match. According to Bloomberg NEF, today’s global electrolyzer capacity of 300 MW must grow to 3000 GW by 2050 to meet clean hydrogen demands of 900 Mt (10X). IEA estimates that every month from January 2030 onwards, three new hydrogen-based industrial plants must be built.
3) Total Cost of green hydrogen – Green hydrogen is fundamentally tied to the cost of renewable electricity, the cost of clean water, CapEx cost of electrolyzer plants, the efficiency of the electrolyzer plant, and finally the cost of storing and transporting the green hydrogen. Today, green hydrogen can cost around €2.5-€5/kg, making it significantly more expensive than the fossil fuel alternatives. Levelized prices need to fall to €1.5/kg by 2050 and possibly sub-€1/kg, to make it competitive with natural gas. However, there are incentives from governments around the world to bring the price down. In the US part of the Inflation Reduction Act created new provisions for clean hydrogen. Under the law, clean hydrogen plants in 2023 can receive a production tax credit up to $3 per kg of hydrogen, for the first 10 years of operation through 2032.
4) Electrolyzer cost – the total installed costs of a GW scale industrial electrolysis plant is currently around 1400 €/kW for Alkaline electrolyzer technology and 1800 €/kW for PEM electrolyzer technology. These need to drop at least 50% by 2050 for green hydrogen to be cost-competitive. However, CapEx improvement plans cannot be a tradeoff resulting in reduced electrolyzer efficiency or durability.
5) Electrolyzer efficiency – Today’s efficiency hovers around 50%. To meet the cost targets, the consensus in the industry is that efficiency needs to continuously improve and be at 75% by 2050. This is a major engineering challenge, plus there is efficiency degradation every year as well.
6) Water Supply – Fresh or clean water must be used in electrolysis. Ocean or salt water (sometimes called seawater) cannot be used. Clean water can be aggregated from collecting rainwater or from a process called desalination. Desalination using reverse osmosis is another very energy-intensive process that also outputs brine (salt-dense water) as a byproduct.
7) Storage – Ideally, electrolysis plants should be located in areas that have abundant renewable electrical power and fresh water. Consumption in the future will likely be places like marinas for ships/vessels and airports for long-haul planes as well as strategic places in the electrical distribution system at the turbine or areas requiring grid stabilization. This means compression, storage, and transportation will be needed. Hydrogen does not degrade over time and can be stored indefinitely. In a gaseous form, it can be stored in ways: pressurized steel tanks and underground reservoirs or salt caverns (for large capacity). Hydrogen can also be liquefied. This would deliver about 75% higher energy density than gaseous hydrogen (stored at 700 bar), But it would waste the equivalent of 25%-30% of the energy contained in the hydrogen to liquefy.
8) Transportation Grid – Moving gaseous hydrogen from the place where it is derived to the place where it will be used is not a straightforward process. There is no piping infrastructure like there is with oil and natural gas pipelines or distribution grids. Because hydrogen is such a small and potentially combustible element, constructing a pipeline is quite challenging.
9) Demand side efficiencies – Just like miles per gallon affects how much fuel a car uses, all applications using electricity or hydrogen need to be made more efficient. A massive effort is required to modernize the existing stock of inefficient assets (buildings, mobility, industrial facilities, and machines, etc.), for higher efficiency or adapt to fun on hydrogen.
10) Funding – In total, investments could amount to almost $15 trillion between now and 2050 – peaking in the late 2030s at around $800 billion per annum1 for 900 Mt (10X). Of this, about $12.5 trillion (85%) relates to the required increase in electricity generation, with only 15% (peaking at almost $150 billion per annum in the late 2030s) relating to an investment in electrolyzer, production facilities, and transport and storage infrastructure. This investment must be coordinated between private-sector action and national and local governments.
The 10 “pieces” of the puzzle that must come together are significant. As with all puzzles, if a single piece is missing, the puzzle is ruined and the 3X scenario would be more likely than the 10X. We have no choice but to put this puzzle together and in this case, we must have all of the pieces in order to meet decarbonization targets and have green hydrogen play its critical role in the effort to halt global warming.
By: Felicity Bradstock View the original article here
There is great optimism around the future of green hydrogen, with many seeing it as a super-fuel that will replace oil-derived options, as well as be highly competitive with electric battery technology. However, we are far from achieving this ambition yet, mainly due to small-scale production operations and high costs. Many companies around the globe have plans to produce green hydrogen, but some are battling challenges that are slowing down the rollout of the clean fuel. Despite improvements in production processes, thanks to greater investment in the sector in recent years, the production and transportation costs of green hydrogen remain much higher than other fuels, including other types of hydrogen.
Producing grey or blue hydrogen, which is derived from fossil fuels, is viewed as relatively low cost, with many companies already relying on this fuel. Grey hydrogen is produced using natural gas. It undergoes a steam methane reforming (SMR) process, which breaks methane apart using high-pressure steam, which creates separate hydrogen, carbon monoxide, and carbon dioxide molecules. This process produces high levels of carbon dioxide, around 9 to 10 tons of CO2 for every ton of hydrogen. But it is also highly cost-effective, so long as natural gas prices remain stable. In July 2022, the cost of grey hydrogen was around $2 per kilo.
In contrast, green hydrogen production methods are more expensive. Green hydrogen is made using renewable energy sources to power an electrolysis process that separates hydrogen from water, producing just steam as a waste product. It is carbon neutral, making it highly attractive for companies looking to decarbonize. However, by July 2022, it cost around $4 to $5 a kilo, or even more, to produce green hydrogen. And some industry experts believe that the high cost of green hydrogen production isn’t going to fall any time soon.
Green hydrogen is viewed by many international agencies, such as the International Energy Agency (IEA) and the International Renewable Energy Agency (IRENA), as a solution to decarbonize ‘hard-to-abate’ sectors. As more governments and private companies around the globe pump funding into green hydrogen operations, there are high hopes that the production cost of green hydrogen to fall substantially, to as low as $0.5 per kilo. However, others believe it will be difficult to drive the cost to lower than $3 per kilo.
IRENA published two studies to drive green hydrogen production worldwide: Green Hydrogen: A Guide to Policy Making in November 2020, and Green Hydrogen Cost Reduction: Scaling up Electrolysers to Meet the 1.5°C climate goal in December 2020. These studies were aimed at encouraging governments and private companies to scale up production, aimed at driving down costs. However, the price of green hydrogen production so far remains elevated, at around 2 to 3 times the cost of grey hydrogen production, when gas prices are stable.
Nevertheless, progress has been seen thanks to greater funding into research and development, with the price of electrolysers falling by around 60 percent since 2010. According to IRENA, they could decrease by a further 40 percent in the short term and by as much as 80 percent in the long term. This cost reduction prediction relies on greater innovation in electrolysis technology to improve its performance, as well as scaling up manufacturing capacity, standardization, and growing economies of scale.
Another challenge to consider is the cost of transportation. Murray Douglas, the head of hydrogen research at Wood Mackenzie, stated that “Hydrogen is pretty expensive to move… “It’s more difficult to move than natural gas … technically, engineering wise … it’s just harder.” And Douglas is not the only one concerned about this. The U.S. Department of Energy (DoE) has reported challenges with green hydrogen including “reducing cost, increasing energy efficiency, maintaining hydrogen purity, and minimizing hydrogen leakage.” The DoE believes greater research is required to “analyze the trade-offs between the hydrogen production options and the hydrogen delivery options when considered together as a system.”
Companies worldwide are now considering the best locations for their green hydrogen production facilities. While there is great potential for the development of plants in Australia, North Africa, and the Middle East, these could be very far from their principal markets. Douglas highlighted the need for a dedicated pipeline, constructed between the producer and end-user if moving green hydrogen by pipe. Alternatively, green hydrogen could be transported as ammonia with nitrogen, which could be shipped and sold to consumers such as fertiliser producers. Otherwise, users would have to crack the ammonia back into nitrogen, which would increase costs and result in energy losses.
For green hydrogen to be as successful as everyone hopes, it will require significant investment to overcome these challenges. Jorgo Chatzimarkakis, the CEO of the industry association Hydrogen Europe, suggests the need for a certification system, to guarantee that any green hydrogen production was powered by renewable sources. Further, a well-researched delivery strategy needs to be developed to ensure that production facilities are adequately linked with green hydrogen markets. This has been seen in projects such as Cepsa’s green hydrogen corridor between southern and northern Europe.
While transportation costs are high, companies already understand how to move green hydrogen as they have been doing it the same way with natural gas for decades. But some are deterred by high costs. Therefore, the industry must drive down production costs to alleviate some of the pressure on transportation. Although the green hydrogen industry continues to face several major challenges, preventing a wide-scale deployment of the clean fuel, greater investment in the sector over the coming decades will likely fix many of these problems and allow for the deployment of global, large-scale green hydrogen production.
By: Casey Crownhart View the original article here
Buckle up, because this week, we’re talking about batteries.
Over the past couple of months, I’ve been noticing a lot of announcements about a new type of battery, one that could majorly shake things up if all the promises I’m hearing turn out to be true.
The new challenger? Sodium-ion batteries, which swap sodium for the lithium that powers most EVs and devices like cell phones and laptops today.
Sodium-ion batteries could squeeze their way into some corners of the battery market as soon as the end of this year, and they could be huge in cutting costs for EVs. I wrote a story about all the recent announcements, and you should give it a read if you’re curious about what companies are jumping in on this trend and what their plans are. But for the newsletter this week, let’s dig a little bit deeper into the chemistry and consider what the details could mean for the future of EV batteries.
One of the reasons that lithium dominates batteries today is absolutely, maddeningly simple: it’s small.
I mean that in the most literal, atomic sense. Lithium is the third-lightest element, heavier than only hydrogen and helium. When it comes down to it, it’s hard to beat the lightest metal in existence if you’re trying to make compact, lightweight batteries.
And cutting weight and size is the goal for making everything from iPhones to EVs: a lightweight, powerful battery means your phone can be smaller and your car can drive farther. So one of the primary ways we’ve measured progress for batteries is energy density—how much energy a battery can pack into a given size.
When you look at that chemical reality, it’s almost no wonder that lithium-ion batteries have exploded in popularity since their commercial debut in the 1990s. There are obviously other factors too, like lithium-ion’s ability to reach high voltages in order to deliver a lot of power, but the benefit of being lightweight and portable is hard to overstate.
Lithium-ion batteries have also benefited from being the incumbent. There are countless researchers scouring the world for new materials and new ways to build lithium-ion cells, and plenty of companies making them in greater numbers—all of which adds up to greater efficiencies. As a result, costs have come down basically every year for decades (with the notable exception of 2022).
And at the same time, energy density is ticking up, a trend I’m personally grateful for because I often forget to charge my phone for days at a time, and it typically works out much better when that happens now than it did a few years ago.
But just because lithium-ion dominates the battery world today doesn’t mean it’ll squash the competition forever.
I’ve written about the growing number of options in the battery industry before, mostly in the context of stationary storage on the electrical grid. This is especially important in the transition to intermittent renewable energy sources like wind and solar.
While backup systems tend to use lithium-ion batteries today since they’re what’s available, many companies are working to build batteries that could eventually be even cheaper and more robust. In other words, many researchers and companies want to design batteries specifically for stationary storage.
New batteries could be made with abundant materials like iron or plastic, for example, and they might use water instead of organic solvents to shuttle charge around, addressing lingering concerns about the safety of large-scale lithium-ion battery installations.
But compared to stationary storage, there are fewer candidates that could work in EV batteries, because of the steep demands we have for our vehicles. Today, most of the competition in the commercial market is between the different flavors of lithium-ion batteries, with some lower-cost versions that don’t contain cobalt and nickel gaining ground in the last couple of years.
That could change soon too, though, because just below lithium on the periodic table, a challenger lurks: sodium. Sodium is similar to lithium in some ways, and cells made with the material can reach similar voltages to lithium-ion cells (meaning the chemical reactions that power the battery will be nearly as powerful).
And crucially, sodium-based batteries have recently been cramming more energy into a smaller package. In 2022, the energy density of sodium-ion batteries was right around where some lower-end lithium-ion batteries were a decade ago—when early commercial EVs like the Tesla Roadster had already hit the road.
Projections from BNEF suggest that sodium-ion batteries could reach pack densities of nearly 150 watt-hours per kilogram by 2025. And some battery giants and automakers in China think the technology is already good enough for prime time. For more on those announcements and when we might see the first sodium-battery-powered cars on the road, check out my story on the technology.
Here’s how sodium batteries could get their start in EVs.
I wrote about the potential for this sort of progress in a story from January about what we might see forbatteries this year.
Sodium could be competing with low-cost lithium-ion batteries—these lithium iron phosphate batteries figure into a growing fraction of EV sales.
Take a tour of some other non-lithium-based batteries:
Iron-based batteries could be a cheap way to store energy on the grid and assuage concerns about safety.
What about using plastic instead?
Some companies want to go beyond batteries entirely to store energy.
A startup says it’ll be ready to turn on the world’s first fusion power plant in five years. Yes, you read that right: five years.
Helion Energy, a fusion startup backed by OpenAI’s Sam Altman, announced that it’s lined up an agreement to sell electricity to Microsoft. The company says its first plant will come online in 2028 and will reach full capacity (50 megawatts of output) within a year after that.
As you might remember, the energy world reached a huge milestone in December when a fusion reaction generated more energy than what was put in to start it. But for a lot of reasons, that symbolic moment doesn’t necessarily mean cheap fusion power is within our grasp. And some experts are pretty skeptical about Helion’s announcement. Read more about the details in this story from my colleague James Temple.
Keeping up with climate
Need a few extra miles of range on your EV? Might as well slap some solar panels on the roof. But don’t expect too much of a boost. (Bloomberg)
For the first time in my entire life, I seem to be experiencing seasonal allergies. And climate change might have something to do with it. (The Atlantic)
Companies might be overselling the potential for so-called “renewable natural gas.” While it can cut emissions relative to fossil sources, critics worry that putting too much stock in methane made from cow manure or food scraps will slow efforts to ditch fossil fuels. (Canary Media)
→ I wrote earlier this year about how the process to make and capture methane from food scraps works. (MIT Technology Review)
Aubrey Plaza is hilarious and a gift to this world, but some people aren’t so happy about a recent ad she did for the dairy industry that takes aim at plant-based milks. (Vox)
India might stop adding new coal power plants to the pipeline. While this wouldn’t stop all current construction, it could be a major boost to the country’s emissions cuts. (Reuters)
A lot of the work to improve battery performance has been basically focused on one half of the device: the cathode. But some companies are working hard to improve the often-overlooked anodes by using silicon. (IEEE Spectrum)
→ Silicon anodes from startup Sila made their debut in fitness trackers nearly two years ago. The next stop? EVs. (MIT Technology Review)
Support for nuclear power in the US just reached its highest level in over a decade, according to a new Gallup poll. (Grist)
Electric vehicles made up 80% of Norway’s new car sales last year. The country provides a picture of the potential future for electrified transport’s benefits (cleaner air!) and challenges (long charging lines). (New York Times)
By: Catherine Clifford View the original article here
Building new transmission lines in the United States is like herding cats. Unless that process can be fundamentally improved, the nation will have a hard time meeting its climate goals.
The transmission system in the U.S. is old, doesn’t go where an energy grid powered by clean energy sources needs to go, and isn’t being built fast enough to meet projected demand increases.
Building new transmission lines in the U.S. takes so long — if they are built at all — that electrical transmission has become a roadblock for deploying clean energy.
“Right now, over 1,000 gigawatts worth of potential clean energy projects are waiting for approval — about the current size of the entire U.S. grid — and the primary reason for the bottleneck is the lack of transmission,” Bill Gates wrote in a recent blog post about transmission lines.
The stakes are high.
Herding cats with competing interests
Building new transmission lines requires countless stakeholders to come together and hash out a compromise about where a line will run and who will pay for it.
There are 3,150 utility companies in the country, the U.S. Energy Information Administration told CNBC, and for transmission lines to be constructed, each of the affected utilities, their respective regulators, and the landowners who will host a line have to agree where the line will go and how to pay for it, according to their own respective rules.
Aubrey Johnson, a vice president of system planning for the Midcontinent Independent System Operator (MISO), one of seven regional planning agencies in the U.S., compared his work to making a patchwork quilt from pieces of cloth.
“We are patching and connecting all these different pieces, all of these different utilities, all of these different load-serving entities, and really trying to look at what works best for the greatest good and trying to figure out how to resolve the most issues for the most amount of people,” Johnson told CNBC.
What’s more, the parties at the negotiating table can have competing interests. For example, an environmental group is likely to disagree with stakeholders who advocate for more power generation from a fossil-fuel-based source. And a transmission-first or transmission-only company involved is going to benefit more than a company whose main business is power generation, potentially putting the parties at odds with each other.
The system really flounders when a line would span a long distance, running across multiple states.
States “look at each other and say: ‘Well, you pay for it. No, you pay for it.’ So, that’s kind of where we get stuck most of the time,” Rob Gramlich, the founder of transmission policy group Grid Strategies, told CNBC.
“The industry grew up as hundreds of utilities serving small geographic areas,” Gramlich told CNBC. “The regulatory structure was not set up for lines that cross 10 or more utility service territories. It’s like we have municipal governments trying to fund an interstate highway.”
This type of headache and bureaucratic consternation often prevent utilities or other energy organizations from even proposing new lines.
“More often than not, there’s just not anybody proposing the line. And nobody planned it. Because energy companies know that there’s not a functioning way really to recover the costs,” Gramlich told CNBC.
Who benefits, who pays?
Energy companies that build new transmission lines need to get a return on their investment, explains James McCalley, an electrical engineering professor at Iowa State University. “They have got to get paid for what they just did, in some way, otherwise it doesn’t make sense for them to do it.”
Ultimately, an energy organization — a utility, cooperative, or transmission-only company — will pass the cost of a new transmission line on to the electricity customers who benefit.
“One principle that has been imposed on most of the cost allocation mechanisms for transmission has been, to the extent that we can identify beneficiaries, beneficiaries pay,” McCalley said. “Someone that benefits from a more frequent transmission line will pay more than someone who benefits less from a transmission line.”
But the mechanisms for recovering those costs varies regionally and on the relative size of the transmission line.
Regional transmission organizations, like MISO, can oversee the process in certain cases but often get bogged down in internal debates. “They have oddly shaped footprints and they have trouble reaching decisions internally over who should pay and who benefits,” said Gramlich.
The longer the line, the more problematic the planning becomes. “Sometimes its three, five, 10 or more utility territories that are crossed by needed long-distance high-capacity lines. We don’t have a well-functioning system to determine who benefits and assign costs,” Gramlich told CNBC. (Here is a map showing the region-by-region planning entities.)
Johnson from MISO says there’s been some incremental improvement in getting new lines approved. Currently, the regional organization has approved a $10.3 billion plan to build 18 new transmission projects. Those projects should take seven to nine years instead of the 10 to 12 that is historically required, Johnson told CNBC.
“Everybody’s becoming more cognizant of permitting and the impact of permitting and how to do that and more efficiently,” he said.
There’s also been some incremental federal action on transmission lines. There was about $5 billion for transmission-line construction in the IRA, but that’s not nearly enough, said Gramlich, who called that sum “kind of peanuts.”
The U.S. Department of Energy has a “Building a Better Grid” initiative that was included in President Joe Biden’s Bipartisan Infrastructure Law and is intended to promote collaboration and investment in the nation’s grid.
In April, the Federal Energy Regulatory Commission issued a notice of proposed new rule, named RM21-17, which aims to address transmission-planning and cost-allocation problems. The rule, if it gets passed, is “potentially very strong,” Gramlich told CNBC, because it would force every transmission-owning utility to engage in regional planning. That is if there aren’t too many loopholes that utilities could use to undermine the spirit of the rule.
What success looks like
Gramlich does point to a couple of transmission success stories: The Ten West Link, a new 500-kilovolt high-voltage transmission line that will connect Southern California with solar-rich central Arizona, and the $10.3 billion Long Range Transmission Planning project that involves 18 projects running throughout the MISO Midwestern region.
“Those are, unfortunately, more the exception than the rule, but they are good examples of what we need to do everywhere,” Gramlich told CNBC.
In Minnesota, the nonprofit electricity cooperative Great River Energy is charged with making sure 1.3 million people have reliable access to energy now and in the future, according to vice president and chief transmission officer Priti Patel.
“We know that there’s an energy transition happening in Minnesota,” Patel told CNBC. In the last five years, two of the region’s largest coal plants have been sold or retired and the region is getting more of its energy from wind than ever before, Patel said.
Great River Energy serves some of the poorest counties in the state, so keeping energy costs low is a primary objective.
“For our members, their north star is reliability and affordability,” Patel told CNBC.
Great River Energy and Minnesota Power are in the early stages of building a 150-mile, 345 kilovolt transmission line from northern to central Minnesota. It’s called the Northland Reliability Project and will cost an estimated $970 million.
It’s one of the segments of the $10.3 billion investment that MISO approved in July, all of which are slated to be in service before 2030. Getting to that plan involved more than 200 meetings, according to MISO.
The benefit of the project is expected to yield at least 2.6 and as much as 3.8 times the project costs, or a delivered value between $23 billion and $52 billion. Those benefits are calculated over a 20-to-40-year time period and take into account a number of construction inputs including avoided capital cost allocations, fuel savings, decarbonization and risk reduction.
The cost will eventually be borne by energy users living in the MISO Midwest subregion based on usage utility’s retail rate arrangement with their respective state regulator. MISO estimates that consumers in its footprint will pay an average of just over $2 per megawatt hour of energy delivered for 20 years.
But there is still a long process ahead. Once a project is approved by the regional planning authority — in this case MISO — and the two endpoints for the transmission project are decided, then Great River Energy and Minnesota Power are responsible for obtaining all of the land use permits necessary to build the line.
“MISO is not going to be able to know for certain what Minnesota communities are going to want or not want,” Patel told CNBC. “And that gives the electric cooperative the opportunity to have some flexibility in the route between those two endpoints.”
For Great River Energy and Minnesota Power, a critical component of engaging with the local community is hosting open houses where members of the public who live along the proposed route meet with project leaders to ask questions.
For this project, the utilities specifically planned the route of the transmission to run along a previously existing corridors as much as possible to minimize landowner disputes. But it’s always a delicate subject.
“Going through communities with transmission, landowner property is something that is very sensitive,” Patel told CNBC. “We want to make sure we understand what the challenges may be, and that we have direct one-on-one communications so that we can avert any problems in the future.”
At times, landowners give an absolute “no.” In others, money talks: the Great River Energy cooperative can pay a landowner whose property the line is going through a one-time “easement payment,” which will vary based on the land involved.
“A lot of times, we’re able to successfully — at least in the past — successfully get through landowner property,” Patel said. And that’s due to the work of the Great River Energy employees in the permitting, siting and land rights department.
“We have individuals that are very familiar with our service territory, with our communities, with local governmental units, and state governmental units and agencies and work collaboratively to solve problems when we have to site our infrastructure.”
Engaging with all members of the community is a necessary part of any successful transmission line build-out, Patel and Johnson stressed.
At the end of January, MISO held a three-hour workshop to kick off the planning for its next tranche of transmission investments.
“There were 377 people in the workshop for the better part of three hours,” MISO’s Johnson told CNBC. Environmental groups, industry groups, and government representatives from all levels showed up and MISO energy planners worked to try to balance competing demands.
″And it’s our challenge to hear all of their voices, and to ultimately try to figure out how to make it all come together,” Johnson said.
By: Catherine Clifford View the original article here
Wind and solar power generators wait in yearslong bureaucratic lines to connect to the power grid, only to be faced with fees they can’t afford, forcing them to scramble for more money or pull out of projects completely.
This application process, called the interconnection queue, is delaying the distribution of clean power and hampering the U.S. in reaching its climate goals.
The interconnection queue backlog is a symptom of a larger climate problem for the United States: There are not enough transmission lines to support the transition from a fossil fuel-based electric system to a decarbonized energy grid.
Surprise fee increases
The Oceti Sakowin Power Authority, a nonprofit governmental entity owned by seven Sioux Indian tribes, is working to build 570 megawatts of wind power generation to sell to customers in South Dakota.
“Economic development through renewable energy speaks to the very heart of Lakota culture and values – being responsible stewards of Grandmother Earth, Unci Maka,” Jonathan E. Canis, general counsel for the Oceti Sakowin Power Authority, told CNBC. “Together our tribes occupy almost 20% of the land area of South Dakota. And the experts who have been measuring our wind resources literally describe them as ‘screamin.’.”
To connect wind power generation to the electric grid and make money from the sale of that power, the Oceti Sakowin Power Authority — like every electricity generator in the U.S. — has to submit an application called an interconnection request to whichever organization is overseeing the coordination of the electric grid in that region. Sometimes it’s a regional transmission planning authority, other times a utility.
In late 2017, the Oceti Sakowin Power Authority paid a $2.5 million deposit to secure a place in line for its application to be reviewed by the Southwest Power Pool, a regional grid operator.
Five years later, in 2022, the Southwest Power Pool came back and told it that the fee to connect to the grid would actually be $48 million. That’s because connecting all that new power to the grid would require major updates to the transmission infrastructure.
The Oceti Sakowin Power Authority had 15 business days to come up with the extra $45.5 million.
“Needless to say, we couldn’t do it and had to drop out,” Canis told CNBC.
Now, the Oceti Sakowin Power Authority is reevaluating the size and composition of the project and plans to reenter the interconnection queue by the end of the year. That could mean another yearslong wait in line.
These burdens are typical.
In 2020, Pine Gate Renewables had a solar project located in the Piedmont region of North Carolina that it expected to cost $5 million to connect to the electric grid. The local utility in charge of overseeing the interconnection process told Pine Gate it would be more than $30 million. Pine Gate had to terminate the project because it couldn’t afford the new fees, its vice president of regulatory affairs, Brett White, told CNBC.
“We view, as a company, the interconnection problem as the biggest impediment to the industry right now and the costs associated with interconnection are the biggest reason that a project dies on the vine,” White said. “It’s the biggest wild card you have going into the project development cycle.”
There are efforts underway to improve the efficiency of the process, but they’re fundamentally putting a Band-Aid on top of an even deeper problem in the United States: There isn’t enough transmission infrastructure to support the energy transition from fossil fuel sources of energy to clean sources of energy.
“You could make the process for the queue as efficient and pristine as possible and it still could not be all that effective because at some point you’re going to run out of transmission headroom,” Wood Mackenzie analyst Ryan Sweezey told CNBC.
Waiting in line
The entire electric grid in the U.S. has installed capacity of 1,250 gigawatts. There are currently 2,020 gigawatts of capacity in the interconnection queue lines around the country, according to a report published Thursday by the Lawrence Berkeley National Laboratory. That includes 1,350 gigawatts of power capacity, mostly clean, looking to be constructed and connected to the grid. The rest, 670 gigawatts, is for storage.
Berkeley Lab pulls interconnection queue data from all of the regional planning territories in the United States and from between 35 and 40 utilities that are not covered by areas with regional planning authorities. The data covers between 85% and 90% of the electricity load in the United States, Joseph Rand, an energy policy researcher and the lead author of the study, told CNBC.
The interconnection process starts with a request to connect to the grid, which officially enters the power generator in the interconnection queue. The next step is a series of studies — the feasibility, system and facilities studies — where the grid operator determines what equipment or upgrades will be necessary to get the new power generation on the grid and what it will cost.
If all the parties can agree, then the power generator and grid operator reach an interconnection agreement, which establishes the grid improvements the power generator will pay for.
The total power capacity that comes out from a fossil fuel-burning power plant is often much greater than the capacity from renewable plants. That means it can take multiple wind or solar power generation plants — and, therefore, interconnection requests — to get the same units of energy online.
A single natural gas plant could be 1,200 megawatts, Sweezey told CNBC. “That’s one request — 1,200 megawatts,” Sweezey said. “Whereas usually if you’re going to get that same amount of capacity with renewables, that’s going to be six, seven, eight, nine, 10 different projects. So that’s 10 different requests in the queue.”
On average, it took a new power generation project 35 months to go from the interconnection request being filed with a grid operator to an interconnection agreement being reached in 2022, according to Berkeley Lab.
How did this process become such a problem?
The U.S. energy grid is a patchwork system of many regional utility companies. Some provide transmission services and some don’t.
In an effort to promote competition, the Federal Energy Regulatory Commission issued an order in 1996 saying transmission service has to be provided to power generators on a nondiscriminatory basis. This allowed all kinds of power generators, including those that do not own transmission infrastructure, to compete. In 2003, it issued another order that standardized the interconnection process for energy generators.
Both orders “attempted to make the services one needs nondiscriminatory and fair to all users, for their respective service,” according to Rob Gramlich, founder of transmission market intelligence firm Grid Strategies.
That process worked well enough when the power generation industry was building large, centrally located energy plants that burned fossil fuels. But the process started to show signs of strain around 2008 when renewable energy started to come online in places where there was not sufficient transmission, Gramlich told CNBC. In April 2008, MISO, one of the regional operators, said it would take 42 years, until 2050, for it to get through its interconnection queue.
Reforms in 2008 and 2012 helped a little bit, Gramlich told CNBC. “But I think everybody’s realizing now that that original process is fundamentally unsuited to the new generation mix.”
The interconnection process is especially bad at estimating battery storage, said White. That’s because transmission planning is always defaulting to the worst-case scenario, but batteries will draw energy from the grid when the demand is low and energy prices are low, and then use that stored power when the grid is at or near capacity. Using worst-case-scenario planning for battery storage fundamentally misses the point of a battery.
“The upgrades that are going to be triggered on the system are going to be very, very extensive and very, very expensive. And so they hand you a bill that reflects that,” White told CNBC.
But that kind of system upgrade “in our mind is totally disassociated from the economics of the asset, and not really looking at the benefit that the project is going to provide to the system,” White said.
Texas makes it easier
The rates of interconnection applications that actually reach commercial completion vary significantly, but none are higher than 38% in the New England region, according to Berkeley Lab. The Texas grid operator, Electric Reliability Council of Texas, or ERCOT, has a completion rate of 31% and is the only other region with a completion rate of over 30%.
On the low end, the California Independent System Operator region has an 13% completion rate and the New York Independent System Operator region is at 15%.
The low percentage of interconnection requests that actually get built is partly because of the high cost to connect.
In the MISO region, for instance, interconnection costs were generally less than $100 per kilowatt-hour from 2008 to 2016, but have risen to a few hundred dollars per kWh for wind and solar, with spikes as high as $1,000 per kWh in some parts of the region, Gramlich told CNBC.
Adding even small amounts of energy to the grid requires infrastructure improvements because it’s nearly at capacity. Pushing those costs onto the builders of individual renewable projects generally makes them economically unsustainable.
“Those projects ended up withdrawing from the queue or terminating, because they don’t pencil anymore,” White told CNBC.
Some of the completion rates are artificially low because developers don’t actually expect to complete them all, but instead shop the same project around to various regional grid operators to get the best deal — what’s called “speculative queuing,” Sweezey told CNBC. It’s not expensive to get into queues, so developers submit applications to get information about which location will require the least expensive upgrades.
For grid operators, having power generators stuff their queues is overwhelming an already taxed system.
“Projects that have come through the process are not being built and becoming operational,” Jeffrey Shields, a PJM Interconnection spokesperson, told CNBC. “There are about 38,000 MW of renewable projects that have no further PJM requirements but are not being built because of siting, supply chain, or other issues facing the industry that are not related to PJM’s interconnection process.”
The long application timelines and expensive upgrades have made Texas a desirable place to build renewable energy projects because the state has its own interconnection application process.
“There is Texas, and then there’s the rest of the country with respects to interconnection,” White of Pine Gate told CNBC. Texas doesn’t require the same level of network upgrades to get power generation connected to the grid so getting a project online in Texas is faster and lower cost than the rest of the country, White said.
“You can put a project in the PJM queue tomorrow and it may not get constructed and built until 2030, whereas if you do the same with the Texas project, right now, it’s probably online in two to three years. So it’s just a much, much shorter timeline to commercial operation for a project in Texas,” White told CNBC.
But Texas also has a unique risk because ERCOT can decide to limit the amount of power that a generator can sell to the market if a particular electric corridor gets overly congested.
“It’s a bit of a double-edged sword,” White told CNBC. But with infrastructure deals, “time kills deals, time kills projects,” White said, so energy developers may prefer to take the risk and get the deal done.
How does this situation get fixed?
In June 2022, FERC issued a proposal on interconnection reforms to address queue backlogs and has since received a slew of public comments.
“We understand that 80 to 85 percent of the projects that are waiting in the queue ultimately are not being built. I think FERC has an opportunity here to make sure that we unlock that bottleneck and that we do all that we can to move those projects forward,” FERC Chairman Willie Phillips said on March 16, according to a statement provided by a FERC spokesperson.
The proposed rule change would offer incremental improvements, like providing information to developers so they can make more informed siting decisions without flooding the queue with speculative requests, and imposing more strict mandates on the regional grid operators to complete studies in a given time period, Rand of Berkeley Lab told CNBC.
“I do think what FERC is proposing has the potential to improve this situation,” Rand told CNBC. But fundamentally, these iterative changes won’t be a silver bullet.
“The energy transition is here. But our updating and expansion of our electric transmission system so far has not even remotely kept pace with that velocity, rate of change we are seeing on the generator-supply side,” said Rand.
There’s also a shortage of the kinds of electrical and transmission engineers required to process all of these applications, Sweezey and White told CNBC. “There’s just not enough people and so we have to think about what is the smartest way to maximize that expertise. And that means getting those engineers out of some of the rote manual data entry and into the actual analysis,” White told CNBC.
Another option is building new sources of clean energy that can be constructed closer to where demand is needed, like small nuclear reactors, Sweezey told CNBC. “I just don’t think people have come to that realization yet.”
Building sufficient transmission to support the energy transition is not necessarily a technical challenge as much as it is a political one.
“The type of coordination and planning that’s required for this kind of large-scale transmission — this involves maybe multiple utilities, multiple grid operators, multiple states, cities, counties, everything, even the feds are all involved — and that is antithetical to the U.S. as structured as a decentralized nation,” Sweezey told CNBC.
But the stakes are high.
“Even with all of the work, with all this great stuff that’s in the IRA and all of the wind that is in the sails of decarbonization in the renewable industry, if you can’t address transmission and infrastructure, then those goals aren’t going to be met,” White told CNBC.
“It really is the bottleneck that’s preventing that from happening.”
Regulators and policymakers must resist the temptation to overcommit to hydrogen for end uses where electrification will ultimately win out.
By: Dan Esposito and Hadley Tallackson View the original article here
This opinion piece is part of a series from Energy Innovation’s policy experts on advancing an affordable, resilient and clean energy system. It was written by Dan Esposito, senior policy analyst in Energy Innovation’s Electricity Program, and Hadley Tallackson, a policy analyst in the Electrification Program at Energy Innovation.
The Inflation Reduction Act has upended hydrogen economics, making “green” hydrogen — electrolyzed from renewable electricity and water — suddenly cost-competitive with its natural gas-derived counterpart.
On the supply side, electrolyzers can help utilities integrate renewables into the grid, speeding the clean electricity transition. On the demand side, electrolysis can cost-effectively decarbonize hydrogen production.
But the new hydrogen economics mean regulators and policymakers must be even more careful to avoid directing the fuel to counterproductive applications like heating buildings.
“Gray” hydrogen, which uses the highly-polluting steam methane reformation, or SMR, process, has long been the cheapest production method, trading around $1.50-2.00 per kilogram in the United States. In comparison, electrolyzed hydrogen costs about $4-8/kg without subsidies. The Inflation Reduction Act’s $3/kg incentive for zero-carbon hydrogen makes green hydrogen cheaper than gray, potentially spurring an electrolyzer boom.
To facilitate utilities connecting newly-cheap electrolyzers to the grid, regulators should set tariffs reflecting their flexibility value, empowering more bullish utility wind and solar resource procurement.
However, cheap hydrogen should not encourage its use in applications better served by direct electrification like buildings or transportation. Regulators should remain wary of gas utility proposals to blend hydrogen into pipelines, as they would achieve few emissions reductions before facing costly dead-ends while increasing threats to public safety. State policymakers should also use caution before directing public funds toward hydrogen light-duty refueling stations, as electric vehicles have substantial cost and performance advantages that risk stranding hydrogen vehicle infrastructure.
Instead, industrial consumers should use green hydrogen to decarbonize their gray hydrogen consumption for a cheaper, cleaner product.
The IRA’s clean hydrogen production tax credits
The Inflation Reduction Act offers a 10-year production tax credit for “clean hydrogen” production facilities. Incentives begin at $0.60/kg for hydrogen produced in a manner that captures slightly more than half of SMR process carbon emissions, assuming workforce development and wage requirements are met. The PTC’s value rises to $1.00/kg with higher carbon capture rates before jumping to $3.00/kg for hydrogen produced with nearly no emissions.
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.
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.
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.
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 calledgreen 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.
By: Tereza Pultarova View the original article here
A nuclear fusion experiment produced more energy than it consumed.
American researchers have achieved a major breakthrough paving the way toward nuclear fusion based energy generation, but major hurdles remain.
Nuclear fusion is an energy-generating reaction that fuses simple atomic nuclei into more complex ones, such as combining atoms of hydrogen into helium. Nuclear fusion takes place in the cores of stars when vast amounts of molecular dust collapse under gravity and create immense amounts of pressure and heat in the nascent stars’ cores.
For decades, scientists have therefore been chasing nuclear fusion as a holy grail of sustainable energy generation, but have fallen short of achieving it. However, a team from the Lawrence Livermore National Laboratory (LLNL) in California may have finally made a major leap to creating energy-giving ‘stars’ inside reactors here on Earth.
A team from LLNL has reportedly managed to achieve fusion ignition at the National Ignition Facility (NIF), according to a statement published Tuesday (Dec. 13). “On Dec. 5, a team at LLNL’s National Ignition Facility (NIF) conducted the first controlled fusion experiment in history to reach this milestone, also known as scientific energy breakeven, meaning it produced more energy from fusion than the laser energy used to drive it,” the statement reads.
The experiment involved bombarding a pencil-eraser-sized pellet of fuel with 192 lasers, causing the pellet to then release more energy than the lasers blasted it with. “LLNL’s experiment surpassed the fusion threshold by delivering 2.05 megajoules (MJ) of energy to the target, resulting in 3.15 MJ of fusion energy output, demonstrating for the first time a most fundamental science basis for inertial fusion energy (IFE),” LLNL’s statement reads.
Still, that doesn’t mean that fusion power is within grasp, LLNL cautions. “Many advanced science and technology developments are still needed to achieve simple, affordable IFE to power homes and businesses, and [the U.S. Department of Energy] is currently restarting a broad-based, coordinated IFE program in the United States. Combined with private-sector investment, there is a lot of momentum to drive rapid progress toward fusion commercialization,” the statement continues.
Even though this is only a preliminary step towards harnessing fusion power for clean energy, LLNL leaders are hailing the accomplishment as a transformative breakthrough. “Ignition is a first step, a truly monumental one that sets the stage for a transformational decade in high-energy density science and fusion research and I cannot wait to see where it takes us,” said LLNL Director Dr. Kim Budil during Tuesday’s press conference.
“The science and technology challenges on the path to fusion energy are daunting. But making the seemingly impossible possible is when we’re at our very best,” Budil added.”
Such conditions lead up to the ignition of the fusion reaction, which, however, in the current experiment was sustained for only a very short period of time. During the experiment, the energy generated by the fusing atoms surpassed the amount of energy required by the lasers igniting the reaction, a milestone known as net energy gain.
Scientists at the laboratory have conducted several fusion experiments in recent years, which haven’t generated the amount of power needed to claim a major breakthrough. In 2014, the team produced about as much energy as a 60-watt light bulb consumes in five minutes. Last year, they managed to reach a power output of 10 quadrillion watts of power — which was about 70% as much energy as consumed by the experiment.
The fact that the latest experiment produced a little more energy than it consumed means that for a brief moment, the reaction must have been able to sustain itself, using its own energy to fuse further hydrogen atoms instead of relying on the heat from the lasers.
However, the experiment only produced 0.4MJ of net energy gain — or about as much is needed to boil a kettle of water, according to the Guardian.
The breakthrough comes as the world struggles with a global energy crisis caused by Russia’s war against Ukraine while also striving to find new ways to sustainably cover its energy needs without burning fossil fuels. Fusion energy is not only free from carbon emissions but also from potentially dangerous radioactive waste, which is a dreaded byproduct of nuclear fission.
The New York Times, however, cautions that while promising, the experiment is only the very first step in a still long journey toward the practical use of nuclear fusion. Lasers efficient enough to launch and sustain nuclear fusion on an industrial scale have not yet been developed, nor has the technology needed to convert the energy released by the reaction into electricity.
The National Ignition Facility, which primarily conducts experiments that enable nuclear weapons testing without actual nuclear explosions, used a fringe method for triggering the fusion reaction.
Most attempts at igniting nuclear fusion involve special reactors known as tokamaks, which are ring-shaped devices holding hydrogen gas. The hydrogen gas inside the tokamak is heated until its electrons split from the atomic nuclei, producing plasma.
The lasers heated up the cylinder to a temperature of about 5.4 million degrees Fahrenheit, which vaporized the cylinder, producing a burst of X-rays. These X-rays then heated up a small pellet of frozen deuterium and tritium, which are two isotopes of hydrogen. As the core of the pellet heated up, the hydrogen atoms fused into helium in the first glimmer of nuclear fusion.
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.”