Green Energy

To continue reducing the costs of solar energy and other clean energy technologies, scientists and engineers will likely need to focus, at least in part, on improving technology features that are not based on hardware, according to MIT researchers. They describe this finding and the mechanisms behind it in Nature Energy. While the cost of installing a solar energy system has dropped by more than 99% since 1980, this new analysis shows that “soft technology” features, such as the codified permitting practices, supply chain management techniques, and system design processes that go into deploying a solar energy plant, contributed only 10 to 15% of total cost declines. Improvements to hardware features were responsible for the lion’s share. But because soft technology is increasingly dominating the total costs of installing solar energy systems, this trend threatens to slow future cost savings and hamper the global transition to clean energy, says the study’s senior author, Jessika Trancik, a professor in MIT’s Institute for Data, Systems, and Society (IDSS). Trancik’s co-authors include lead author Magdalena M. Klemun, a former IDSS graduate student and postdoc who is now an assistant professor at the Hong Kong University of Science and Technology; Goksin Kavlak, a former IDSS graduate student and postdoc who is now an associate at the Brattle Group; and James McNerney, a former IDSS postdoc and now senior research fellow at the Harvard Kennedy School. The team created a quantitative model to analyze the cost evolution of solar energy systems, which captures the contributions of both hardware technology features and soft technology features. The framework shows that soft technology hasn’t improved much over time—and that soft technology features contributed even less to overall cost declines than previously estimated. Their findings indicate that to reverse this trend and accelerate cost declines, engineers could look at making solar energy systems less reliant on soft technology to begin with, or they could tackle the problem directly by improving inefficient deployment processes. “Really understanding where the efficiencies and inefficiencies are, and how to address those inefficiencies, is critical in supporting the clean energy transition. We are making huge investments of public dollars into this, and soft technology is going to be absolutely essential to making those funds count,” says Trancik. “However,” Klemun adds, “we haven’t been thinking about soft technology design as systematically as we have for hardware. That needs to change.”

The hard truth about soft costs

Researchers have observed that the so-called “soft costs” of building a solar power plant—the costs of designing and installing the plant—are becoming a much larger share of total costs. In fact, the share of soft costs now typically ranges from 35 to 64%. “We wanted to take a closer look at where these soft costs were coming from and why they weren’t coming down over time as quickly as the hardware costs,” Trancik says. In the past, scientists have modeled the change in solar energy costs by dividing total costs into additive components—hardware components and non-hardware components—and then tracking how these components changed over time. “But if you really want to understand where those rates of change are coming from, you need to go one level deeper to look at the technology features. Then things split out differently,” Trancik says. The researchers developed a quantitative approach that models the change in solar energy costs over time by assigning contributions to the individual technology features, including both hardware features and soft technology features. For instance, their framework would capture how much of the decline in system installation costs—a soft cost—is due to standardized practices of certified installers—a soft technology feature. It would also capture how that same soft cost is affected by increased photovoltaic module efficiency—a hardware technology feature. With this approach, the researchers saw that improvements in hardware had the greatest impacts on driving down soft costs in solar energy systems. For example, the efficiency of photovoltaic modules doubled between 1980 and 2017, reducing overall system costs by 17%. But about 40% of that overall decline could be attributed to reductions in soft costs tied to improved module efficiency. The framework shows that, while hardware technology features tend to improve many cost components, soft technology features affect only a few. “You can see this structural difference even before you collect data on how the technologies have changed over time. That’s why mapping out a technology’s network of cost dependencies is a useful first step to identify levers of change, for solar PV and for other technologies as well,” Klemun notes.

Static soft technology

The researchers used their model to study several countries, since soft costs can vary widely around the world. For instance, solar energy soft costs in Germany are about 50% less than those in the U.S. The fact that hardware technology improvements are often shared globally led to dramatic declines in costs over the past few decades across locations, the analysis showed. Soft technology innovations typically aren’t shared across borders. Moreover, the team found that countries with better soft technology performance 20 years ago still have better performance today, while those with worse performance didn’t see much improvement. This country-by-country difference could be driven by regulation and permitting processes, cultural factors, or by market dynamics such as how firms interact with each other, Trancik says. “But not all soft technology variables are ones that you would want to change in a cost-reducing direction, like lower wages. So, there are other considerations, beyond just bringing the cost of the technology down, that we need to think about when interpreting these results,” she says. Their analysis points to two strategies for reducing soft costs. For one, scientists could focus on developing hardware improvements that make soft costs more dependent on hardware technology variables and less on soft technology variables, such as by creating simpler, more standardized equipment that could reduce on-site installation time. Or researchers could directly target soft technology features without changing hardware, perhaps by creating more efficient workflows for system installation or automated permitting platforms. “In practice, engineers will often pursue both approaches, but separating the two in a formal model makes it easier to target innovation efforts by leveraging specific relationships between technology characteristics and costs,” Klemun says. “Often, when we think about information processing, we are leaving out processes that still happen in a very low-tech way through people communicating with one another. But it is just as important to think about that as a technology as it is to design fancy software,” Trancik notes. In the future, she and her collaborators want to apply their quantitative model to study the soft costs related to other technologies, such as electrical vehicle charging and nuclear fission. They are also interested in better understanding the limits of soft technology improvement, and how one could design better soft technology from the outset.

Today’s electric cars use large lithium-ion batteries, which work fairly well. They can store a fairly high amount of energy in relation to their weight. They also don’t need to be completely discharged each time before being recharged, so you can usually put the car on charge when it suits you without thinking too much about whether you are damaging the battery.

But these batteries still don’t have enough energy density for emerging applications and EVs. They are unstable and flammable, so it is perhaps not surprising that the search is on for alternatives.

“Solid-state batteries can be the future for tomorrow’s electric cars,” says Daniel Rettenwander, a professor at NTNU’s Department of Materials Science and Engineering.

Rettenwander is part of a research team studying how solid-state batteries can be charged much faster than is currently possible, and be made safer and easier to recycle. Their research has been published in Nature Communications. The researchers in Norway collaborated with colleagues in Austria, Germany and the U.S..

The findings may be important as part of the work to get more people to use solid-state batteries, perhaps as a technology which at some point will be ready for commercialization.

Advantages of solid state batteries

Solid-state batteries have several advantages compared to lithium-ion batteries. They can have higher voltage and higher energy capacity for energy storage in relation to their weight and volume.

These kinds of batteries are used today in pacemakers and portable electronics, where it is particularly important for the batteries to be small. Small batteries are also easier to make—which is why solid-state batteries are only commercial available at small scale. The production costs for larger batteries would be far too high since their manufacture is expensive.

Solid-state batteries can also be safer than conventional lithium-ion batteries. Among other characteristics, they tolerate much greater temperature fluctuations than lithium-ion batteries. This is especially nice on cold winter mornings in the garage or on long trips.

In addition, solid-state batteries are less flammable than lithium-ion batteries because they do not contain a liquid electrolyte. These electrolytes are charged substances that are used to conduct electricity. As their name suggests, solid-state batteries use solid substances instead of the far more common liquid electrolytes.

Faster to recharge

But solid-state batteries could be faster to charge than they are today. One challenge that needs to be overcome is that it is more difficult to use solids than liquids to transfer electrical charges.

“We have investigated how we can charge solid-state batteries more efficiently at much higher current, which reduces the charging time of any electronic device or EV using these batteries,” says Florian Flatscher, a Ph.D. candidate who worked with Rettenwander and Verena Reisecker from Graz University of Technology.

The charging mechanism is very complicated for most of us to understand, but those who already know a bit about this can take a look at the article here. The results from the research can also contribute to solid-state batteries being easier to recycle.

Can be safer

The researchers also know more about why solid-state batteries break down. It goes without saying that this is important.

“Solid state batteries also use lithium. We see that lithium activity can play a critical role when solid-state batteries stop working,” says Rettenwander.

This is a completely new insight, and is a step on the way to understanding the underlying mechanisms behind what are called “dendrites.” These pose a problem in solid state batteries. In this context, dendrites are special lithium particles that can be formed by corrosion and mechanical stress. These lithium particles can in turn short circuit conductors.

“We now know more about how we can prevent such dendrites from forming. That’s a real advantage for safety,” says Flatscher.

Solid-state batteries are more expensive than lithium batteries, but this may change when they are mass produced. A number of manufacturers have announced that they are developing cars with solid-state batteries. The first ones may be on the market as early as 2024.

In countries such as Peru, Bolivia and Chile, it’s not uncommon for people who live in foggy areas to hang up nets to catch droplets of water. The same is true of Morocco and Oman. These droplets then trickle down the mesh and are collected to provide water for drinking, cooking and washing.

As much as several hundred liters of water can be harvested daily using a fog net only a few square meters in area. For regions with little rain or spring water, but where fog is a common occurrence, this can be a blessing.

One crucial drawback with this method, however, is atmospheric pollution, since the hazardous substances also end up in the droplets of water. In many of the world’s major cities, the air is so polluted that any water harvested from fog isn’t clean enough to be used untreated either for drinking or for cooking.

Researchers at ETH Zurich have now developed a method that collects water from fog and simultaneously purifies it. This uses a close-mesh lattice of metal wire coated with a mixture of specially selected polymers and titanium dioxide. The polymers ensure that droplets of water collect efficiently on the mesh and then trickle down as quickly as possible into a container before they can be blown off by the wind. The titanium dioxide acts as a chemical catalyst, breaking down the molecules of many of the organic pollutants contained in the droplets to render them harmless. Their work has been published in Nature Sustainability.

“Our system not only harvests fog but also treats the harvested water, meaning it can be used in areas with atmospheric pollution, such as densely populated urban centers,” Ritwick Ghosh explains. A scientist at the Max Planck Institute for Polymer Research in Mainz, Ghosh conducted this project while on an extended guest stay at ETH Zurich. During this time, he was a member of the group led by Thomas Schutzius, who has since taken up a post as professor at the University of California, Berkeley.

Photocatalytic memory

Once installed, the technology needs little or no maintenance. Moreover, no energy is required apart from a small but regular dose of UV to regenerate the catalyst. Half an hour of sunlight is enough to reactivate the titanium oxide for a further 24 hours—thanks to a property known as photocatalytic memory.

Following reactivation with UV, the catalyst also remains active for a lengthy period in the dark. With periods of sunlight often rare in areas prone to fog, this is a very useful quality.

The new fog collector was tested in the lab and in a small pilot plant in Zurich. Researchers were able to collect 8% of the water in artificially created fog and break down 94% of the organic compounds that had been added to it. Among the added pollutants were extremely fine diesel droplets and the chemical bisphenol A, a hormonally-active agent.

Potential use in cooling towers

In addition to harvesting drinking water from fog, this technology could also be used to recover water used in the cooling towers. “In the cooling towers, steam escapes up into the atmosphere. In the United States, where I live, we use a great deal of fresh water to cool power plants,” says Schutzius. “It would make sense to capture some of this water before it escapes and ensure that it is pure in case you want to return it back to the environment.”

Past research by Ghosh focused on water recovery from cooling towers. He would now like to advance this technology and explore marketable applications. His hope is to make greater use of fog and steam as a hitherto underutilized source of water and thereby play a role in alleviating the scarcity of this vital resource.

Lawmakers in some states have been laying the groundwork to add geothermal power to the electrical grid and pump underground heat into buildings. Now, a technological breakthrough could dramatically expand those ambitions—and perhaps unleash a new wave of policies to tap into geothermal sources.

Last month, a company announced the successful demonstration in the West of a new drilling technique that it says will greatly expand where geothermal plants could be built. And in the Eastern half of the country, where geothermal’s potential is mostly as a heating and cooling source, a community recently broke ground on the first utility-run thermal energy network.

Some officials say those advances show great promise. A handful of states approved laws this year and others are considering measures that would provide money and regulations to help the industry.

“There have been enormous technological breakthroughs in geothermal,” Colorado Democratic Gov. Jared Polis said in an interview with Stateline. “More geographic areas are now eligible and capable of producing inexpensive geothermal energy. You’re seeing more and more states addressing geothermal opportunities with the urgency that Colorado is.”

In the West, some states see geothermal power plants as a crucial source of “always-on” clean electricity—a resilient energy supply to bolster grids supplied by wind and solar.

At the same time, some lawmakers in Eastern states believe networks of underground heat could replace gas-powered furnaces for many neighborhoods, campuses and commercial buildings.

In both cases, supporters believe the transition to geothermal could draw on the drilling and pipeline construction expertise of oil and gas workers.

Still, it will take a lot to expand geothermal power. Exploratory drilling is expensive and uncertain, and industry leaders say government backing is required to make that initial phase manageable for companies.

Meanwhile, the drilling technique of injecting water to fracture rock has proven controversial in oil and gas operations. While geothermal projects don’t use the same chemicals that have been linked to groundwater pollution, other concerns—such as increased seismic activity—could challenge new proposals.

Unleashing potential

Last month, Texas-based Fervo Energy announced that its pilot plant in Nevada had successfully demonstrated the first commercially viable enhanced geothermal technology. Historically, geothermal power—which brings steam to the surface that powers turbines—has relied on sites with naturally occurring heat, fluid and permeable rock. Enhanced systems use oil and gas drilling techniques to create artificial reservoirs.

Sarah Jewett, the company’s vice president of strategy, said locations with permeable rock are limited and unpredictable. Horizontal drilling technology can be used to create that permeability and pump water into hotspots underground.

“This is the thing that really unleashes the potential of geothermal power, but it’s never been demonstrated on a commercial level in the U.S. before,” she said. “A lot of people said it couldn’t be done. This opens up massive new geographies [for geothermal power production].”

The plant will connect to Nevada’s grid later this year, providing 3.5 megawatts of electricity to power Google data centers. Fervo has started construction on another project in Utah that is expected to provide 400 megawatts by 2028. That’s enough to power 300,000 homes.

Geothermal provides less than half a percent of the nation’s electricity. Supporters believe that advances in technology will eventually enable it to power as much as 20% of the U.S. grid.

Fervo’s announcement could supercharge the ambitions of some Western states, which have been working to bring more geothermal power online. The Western Governors’ Association, chaired by Polis, has spearheaded an initiative on the issue and recently issued a report outlining several policy recommendations.

Industry leaders have called for clear policy guidelines and well-staffed permitting regimes, as well as public funding to support exploratory drilling, which can be financially risky for companies. They also urged more regulators to issue “clean firm” power standards such as California’s 1,000-megawatt order in 2021, which directed utilities to build out more projects from on-demand resources like geothermal.

In Colorado, lawmakers passed a slate of geothermal measures this year, including a framework for regulators to approve new geothermal operations. Under the measure, the state’s Oil and Gas Conservation Commission was renamed the Energy and Carbon Management Commission and given oversight of geothermal projects.

“They now have an expedited approval process for geothermal drilling,” Polis said. “There really hadn’t been an easy way to do that before.”

Other bills signed by Polis will create a $35 million tax credit for geothermal electricity projects and allow gas utilities to establish thermal energy networks. Lawmakers also provided funding to help Colorado Mesa University expand its geothermal heating and cooling system.

Earlier this year, New Mexico state lawmakers passed a measure to provide loans and grants for geothermal projects and a funding increase to help state regulators speed up permitting decisions. The bill sailed through the legislature with near-unanimous support, but Democratic Gov. Michelle Lujan Grisham declined to sign it, surprising backers.

“New Mexico has some of the easiest access to hot rock because of our geology, and we also have an availability of drilling rigs now in the oil and gas industry that can be put to use,” said state Sen. Jerry Ortiz y Pino, a Democrat who sponsored the bill.

Ortiz y Pino said lawmakers are hoping to meet with Lujan Grisham, address her objections and revive the bill next year. The governor, who cited fiscal responsibility in her veto of a tax credit package that included geothermal projects, did not respond to a request for comment.

Meanwhile, West Virginia leaders passed a law last year to establish a regulatory program for geothermal energy. The state has underground hotspots at relatively shallow depths compared with other Eastern states.

“We wanted to have the groundwork in place so if companies wanted to look at West Virginia, it wasn’t an unknown,” said Del. Adam Burkhammer, a Republican who sponsored the bill. “We’re not overregulating, we’re just establishing a clear path forward.”

Earlier this year, drilling began on the state’s first geothermal test well.

Thermal networks

In many Eastern states, the underground hotspots needed to produce electricity are many miles below the surface, making power production impractical with existing technology. But heating and cooling through geothermal can be achieved at much shallower depths, and many lawmakers see great promise.

“The potential is wildly exciting,” said Maryland Del. Lorig Charkoudian, a Democrat who is drafting legislation to enable geothermal heating networks. “This is a really important piece of the transition from fossil fuel to non-combusting clean energy.”

Geothermal systems bring heat from underground using piped fluids, then use a heat exchanger to transfer it to a building’s ventilation system. In warm months, the same process can cool buildings by sending excess heat underground.

Such systems are gaining momentum as a solution for individual homes and even large campuses. But Charkoudian and others want utilities to run pipelines to create thermal energy networks through towns and cities, taking advantage of an existing workforce and rate structure.

Charkoudian is drafting a bill that would allow gas utilities to build networked geothermal systems, focused first on marginalized communities. She expects to introduce the measure next year.

“When you combine super-efficient ground-source heating and cooling with a networked system, you get the most efficient way possible to heat and cool an entire neighborhood,” she said.

Such networks, she noted, also could allow high-energy users like data centers to transfer “waste heat” to nearby buildings that need it.

The push in Maryland follows a law passed in New York last year to establish a regulatory structure for thermal energy networks. New York lawmakers also voted overwhelmingly this year to expand the drilling depth for such systems below 500 feet, which backers argued was necessary to install them in dense neighborhoods.

Earlier this year, Framingham, Massachusetts, broke ground on the first utility-run geothermal network pilot project in the country.

And in Vermont, lawmakers hope to advance next year a proposal to create a regulatory structure for such thermal energy networks. As just one gas utility covers a third of the state’s area, the bill would also allow such networks to be managed by towns, nonprofits or homeowners associations.

In addition to lowering emissions, backers say the bill could help with heating prices, as rising fuel costs are a major concern in a state where nearly half of residents rely on heating oil.

“There are ways to build local [geothermal] wells and have communities own and operate their own local energy supply,” said Debbie New, lead coordinator with the Vermont Community Geothermal Alliance. “There are municipalities that are interested and saying they really need this bill to pass in order to move forward.”

Stateline is part of States Newsroom, a national nonprofit news organization focused on state policy.

A team of hydrologists and bioengineers affiliated with several institutions across Europe has found, via modeling, that building dams to generate hydroelectricity in Africa may be not be a cost-effective approach in light of falling costs for solar and wind power. In their study, reported in the journal Science, the group developed models projecting energy needs up to the year 2050. Currently, Africa’s energy needs are provided mostly by fossil fuels—up to 70% comes from burning coal, gas or diesel fuel. Africa is also in transition, as areas without electricity seek to join the grid. That, plus a growing population, suggest that Africa is going to require a lot more electricity in the coming years. Fortunately for the planet, most countries in Africa have pledged to reduce carbon emissions. And most have suggested that the way to achieve that goal is to build more dams to produce more hydroelectricity. But that approach might not be the most sensible one, according to work by the team on this new effort. Noting the falling costs for producing electricity using solar or wind, the team wondered if they might now be more cost-effective than building dams. To find out, the group collected data from a host of agencies regarding projected energy demands across the continent in the coming years. They also obtained data regarding the costs of building and maintaining hydro dams and solar- and wind-power-generating projects. They then input the data into several models, adding other information such as population growth statistics and projected rainfall in the coming decades. They ran their models under several scenarios to provide comparisons of cost-effectiveness of building hydroelectric facilities versus solar and wind projects. The different scenarios involved such things as fluctuations in the cost of fossil fuels, changes in amount of rainfall, and increases in atmospheric temperatures. The research team found that under most scenarios, building new hydroelectric facilities was not as cost-effective as building new wind and solar facilities. As an example, they found that under the most optimistic conditions, approximately a third of all the hydro-facilities currently planned will likely be uneconomical compared to renewables by the time construction starts.

Contact Energy expects to have more than 95% of its New Zealand generation renewable by mid-2027 as it moves forward with plans to build new geothermal and solar-powered plants.

The company plans to apply for consent to build a 160 megawatt solar farm northwest of Auckland before the end of this year, the Wellington-based company said Monday. A final investment decision on a solar farm near Christchurch is expected in coming months.

Contact has already committed almost NZ$1.2 billion ($720 million) to the construction of two North Island geothermal projects, the first of which is scheduled to be completed this year. It expects to make a final investment decision on a new 180 MW geothermal station near Taupo in early 2024.

New Zealand generates more than 80% of its electricity from renewable sources and the government aspires to raise that to 100% by 2030. Last week, BlackRock Inc. launched a NZ$2 billion fund aimed at investing in green energy projects in the country.

As it adds renewable plants, Contact is shutting down gas-fired turbines, such as those at Te Rapa, near Hamilton, which closed on June 30, and it expects to decommission another plant in Taranaki at the end of 2024. It is also investigating a grid-scale battery system to boost security of supply.

“With more intermittent renewables being introduced, grid-scale batteries will play an important role by storing energy during periods of low demand and discharging power into the grid during the peaks,” said Chief Executive Officer Michael Fuge. “This investment will reduce our reliance on gas peaking plant.”

Contact’s capital spending on growth projects was NZ$472 million in the 12 months ended June 30, and it projects spending as much as NZ$500 million in the following year, according to its annual results presentation Monday.

It reported net income dropped 30% to NZ$127 million after a provision. Excluding the provision, underlying profit rose 16%.