Wake-up call | Energy-sapping turbulence at offshore wind projects 'vastly underpredicted'

'Velocity deficits' equal to 10% drop in wind speed modelled by ArcVera at zones in US Atlantic in the frame for arrays built around ultra-large class, 12MW-plus units

Source: Recharge News | By Darius Snieckus

The wind industry’s Olympian drive to continue upscaling offshore turbine size could come under the microscope after new calculus concluded conventional engineering modelling of ‘wake’ – the turbulence created by rotor blades as wind moves through an array – has “vastly underpredicted” energy losses linked to so-called “external wakes” – particularly for the ultra-large-class machines now heading for the water.

The work by consultancy ArcVera, which studied long-range wake loss potential at project development zones off New York in the US Atlantic, found “velocity deficits” as high as one metre per second – equal to a 10% drop in wind speed – “could persist up to or greater than 100km downwind” of offshore developments using 12MW-plus models.

“This new study provides an important cautionary lesson as the wind industry proceeds to ever-larger wind turbine models with greater farm density across the globe,” Greg Poulos, CEO of ArcVera, said of the findings, which used high-fidelity Weather Research and Forecasting (WRF) numerical weather prediction modelling run with wind farm parameterisation (WFP) software to factor in the effects of turbines at a site

“WRF-WFP’s results here show that engineering wake... models currently under-predict long-range wake losses by a significant margin. Unexpected losses are likely to accrue from wind farms once thought to be too far away to be material to project performance.”

Mark Stoelinga, head of Atmospheric Science Innovation at ArcVera, added: “This [underestimate] is leading to long-range energy deficits much greater than expected by most subject matter experts in the industry.”

The research, scoped over a swathe of the New York Bight, where the state held a record-setting, $4.4bn leasing round this year, was sparked by the fact that engineering models commonly used in the wind industry to this point have been validated internal and “nearby” external wakes but not over long distances or for large nameplate, 12MW-plus, machines with 200-metre-plus diameter rotors.

ArcVera noted that WFP in WRF “has been validated against SCADA recorded production for an [in-house] onshore case, and it was accurate with respect to long-distance wakes within 16% at a 5km, 50-metre rotor diameter range”.

“In the onshore validation study that we conducted in Iowa, USA, wakes were found to travel over 40 km overland, in stable atmospheric conditions. Over the ocean, it is common for atmospheric stability to be enhanced, especially when warm air flow passes over colder underlying water,” said Stoelinga.

“We also surmise that the very large turbines used in the study produce unusually strong wakes that cannot easily recover their lost momentum, especially under enhanced atmospheric stability conditions.

Consultancy DNV in 2020 flagged the impact the so-called “blockage effect” and wake in general could have on the overall economics of offshore wind power.

'People will wonder why they put solar on land at all': pioneer says floating PV can beat wind

Ocean Sun's hiring of a top Equinor expert to help 'take it to the next level' reflects its ambition to play a key role in the energy transition, says CEO Børge Bjørneklett

Source: Recharge News | By Andrew Lee

It’s not uncommon to hear predictions that renewable energy’s next big leap forward will come with a boom in floating generation – but Børge Bjørneklett is convinced that it will be led by solar modules, not wind turbines.

As CEO of Norwegian floating PV pioneer Ocean Sun, Bjørneklett's bullishness over the technology’s prospects is hardly surprising, but he insists the data backs him up when he claims the fledgling sector is on the cusp of a boom that could outstrip even the growth tipped for foundation-free wind turbines.

“The application area is so much larger [than for floating wind] if you look at irradiation maps of the world, particularly in Southeast Asia,” he tells Recharge. “It’s also much more lean [in materials and deployment]”.

The application area is so much larger… if you look at irradiation maps of the world.

And while floating wind “still has a long way to go on cost”, Bjørneklett claims floating PV, and in particular Ocean Sun’s patented 'flotation ring' polymer membrane technology, is already “in many areas the most affordable source of energy”.

Floating wind’s many advocates may take issue with his analysis, but Ocean Sun – which is working with the likes of Statkraft and Fred Olsen Renewables, and says it is in discussions over more than 3GW of deployments – made a powerful statement of intent in February, when it hired Nenad Keseric as its new chief operating officer from Equinor.

Keseric spent more than a decade helping the Norwegian energy giant carve out a leading position in floating wind, and Bjørneklett claims his new hire is well-placed to help take Ocean Sun “to the next level” towards gigawatt-scale deployments around the world.

Ocean Sun is far from the only player in the fast-emerging floating solar market, which in recent years has been dominated by China’s Sungrow and France’s Ciel & Terre, both pioneers in the market.

But the Oslo-listed Norwegian group’s differentiator rests with its use of hydro-elastic membranes with mooring systems based on fish farming, rather than the rigid pontoons or floats more usually employed to place PV modules on lakes, reservoirs or even the open sea.

Water cooler moment

That allows highly efficient dissipation of heat into the surface below, effectively meaning the system is cooled by water, rather than air, which in Bjørneklett’s phrase has a “very interesting effect” on energy yield of around 0.4% per degree-centigrade, that can result in an increase of up to 10% compared to pontoons or ground-mounted panels.

The advantages of membrane deployment over pontoons does not stop at energy yield, according to Bjørneklett, with Capex reduced by the use of polymer materials around the perimeter of the membranes.

Ocean Sun’s 600kW circular membranes need up to 15-times less container volume to be transported than rival systems, he claims, and can be “unpacked like a big pancake” for the addition of modules, in the case of which are supplied by China’s GCL System.

Asked to put a cost-of-energy figure on its system, Bjørneklett says that depends heavily on irradiation levels and the size of system. “But we can now deploy systems for well under $500,000 per megawatt,” with the gap on ground-mounted systems narrowing fast, he claims.

The technology has also shown it can survive harsh weather conditions, with a prototype in the Philippines – one of three pilots worldwide – coming through tropical storms and monsoons.

Ocean Sun’s business model is as a licensor of technology, and the company, founded in 2016, is working with several big names in the energy sector as they advance their own ambitions.

Perhaps most strikingly, Ocean Sun is part of a project to build a 2.1GW floating PV plant on the Saemangeum tidal flat on the Yellow Sea coast of South Korea that is among the largest planned globally.

A 2MW project in Albania led by Statkraft is currently awaiting delivery of its modules, and

earlier in 2021 Ocean Sun announced it would link with Fred Olsen Renewables and others for a 250kW pilot deployment off the Canary Islands, as part of the EU’s Horizon 2020 programme.

The Canary Islands project, Bjørneklett explains, will test how Ocean Sun’s systems perform in less sheltered open-water conditions, which present the greatest challenges to floating solar systems.

Asian opportunity

But the firm’s CEO expects the vast majority of opportunities globally to come in coastal or sheltered areas, or inland waters, with Asia offering particular promise.

With onshore renewables often facing limited land availability, the region’s coastal megacities will look offshore for their power, Bjørneklett predicted, claiming floating solar has a big card up its sleeve compared to wind at sea.

“It’s flat, can sit a few kilometres away from big cities and you can’t even see it,” he says.

Bjørneklett concedes that the technology works best “between the 45th parallels” – so roughly below southern France in Europe and northern Japan in Asia – as “if you go too far north and south we suffer a bit on panel inclination”.

Even so, according to Bjørneklett, such is the potential for floating solar that it is not just floating wind that is in its sights – even onshore PV should start looking over its shoulder.

“I think to be a bit futuristic, people will ask themselves why they put up solar panels on land at all,” he says.

Bjørneklett’s prediction of global supremacy may be too rich for some, given that floating solar currently has only around 3GW operational around the world, a tiny fraction of the total renewables fleet.

However, there are plenty of objective observers willing to predict floating solar will have a big role to play.

Fitch Solutions said late last year it sees potential for 10GW of additions as soon as 2025, while DNV GL – which in 2020 established a joint industry partnership for the sector – has cited estimates that deploying panels on inland man-made waters alone has a potential to add four terawatts of power capacity worldwide.

‘EU’s 2030 green hydrogen mandates would drive up power demand and make electricity punishingly expensive’

The European Commission’s H2 strategy is reckless and high risk, says independent non-profit organisation Transport & Environment

Source: Recharge News | By Leigh Collins

Meeting the European Commission’s planned mandates for green hydrogen in 2030 would increase electricity demand by 17% at a time when power prices are already at an all-time high, according to Brussels-based independent non-profit organisation Transport & Environment (T&E)

In its latest Renewable Energy Directive proposal, the commission wants to replace 50% of the fossil-gas-derived grey hydrogen used in Europe by 2030 with green H2 produced from renewables by 2030. On top of this, also by 2030, it wants 2.6% of the energy demand from transport to come from so-called RFNBOs — renewable fuels of non-biological origin, which includes hydrogen and synthetic “e-fuels” produced from green H2. This 2.6% includes road and rail transport, as well as aviation and shipping.

Combined, these two mandates would require about 500TWh of renewable energy, said T&E — equivalent to all the wind power currently generated in Europe, or France’s total electricity consumption.

“The 2.6% of green hydrogen and e-fuels will require more renewable electricity in 2030 than all the electricity consumed by battery electric vehicles (cars, buses, trucks) in that year,” said T&E in a statement.

It added: “The European energy grid is gradually decarbonising with more renewables and less fossil-fuel coal and gas-powered electricity. But without additional renewables tied to hydrogen targets, the EU’s plan will likely result in renewables being diverted from the grid and undercut the emissions savings from electric vehicles by making the grid dirtier. With gas the most common marginal fuel to plug gaps, this strategy would be punishingly expensive with gas prices so high.”

Geert Decock, electricity and energy manager at T&E, added: “The EU is playing a high risk hydrogen strategy. We do need hydrogen for ships and planes, but it is reckless to heap unnecessary pressure on wind and solar when clean electricity will be needed to power the growing number of electric cars and heat pumps for homes.

“The EU must ensure that any hydrogen production is coupled with new renewable energy generation. Otherwise today’s high gas and electricity prices will feel like a bargain compared with what’s to come.”

'Green hydrogen developers fear electrolysers will quickly sell out when the ketchup effect kicks in', says Nel CEO

Jon André Løkke tells Recharge that his company, one of the world's leading electrolyser makers, is in discussions with clients about reserving manufacturing capacity for their projects

Source: Recharge News | By Leigh Collins

Readers of a certain age may be familiar with the difficulties of getting thick tomato ketchup out of a glass bottle — holding it upside-down doesn’t work, it has to be shaken vigorously or whacked on the base until the sauce starts flowing, and then it suddenly gushes out, often smothering the plate.

Jon André Løkke, the chief executive of leading electrolyser manufacturer Nel, believes this “ketchup effect” is a metaphor for today’s hydrogen sector.

In other words, gigawatts of orders are ready to be signed off, but will not be until the industry gets the metaphorical whack on the bottom of the bottle from governments, and then OEMs will suddenly be swamped, leaving customers scrambling to place orders before manufacturing capacity is swallowed up.

“Customers are increasingly concerned about securing access to production capacity… and [our] plant may soon end up being sold out,” Løkke tells Recharge, adding that Nel has already “initiated capacity reservation discussions with a selected number of clients”.

This fits with recent analysis by US investment bank Jefferies, which found that global electrolyser manufacturing capacity will not be big enough to meet demand in 2030, even in the lowest demand scenarios.

Løkke explains that the company’s new fully automated 500MW factory in Herøya, Norway, was completed in September, with production now being ramped up to meet “actual customer demands”, with plans to expand capacity to 2GW once the proverbial ketchup starts flowing.

Nel’s order pipeline already consists of more than 800 projects adding up to more than 11GW of electrolysers, with its largest being a 1.6GW facility.

It will be ‘first-come-first-serve’ principle so that the clients that commit first will be secured first.

“However, we are still waiting for the “ketchup effect” where firm commitments are made,” Løkke tells Recharge. “Here it will be ‘first-come-first-serve’ principle so that the clients that commit first will be secured first.

“Given that we already have developed a fully automated production concept and spent more than three years on that, we also believe that we will be able to add additional capacity relatively quickly. Copy/paste is faster than developing from scratch. Hence, this will also depend on the demand from end customers.”

He explains that demand for electrolysers will grow rapidly once countries and regions provide “clear and predictable policy frameworks”.

“It’s not just about providing subsidies or carbon contracts for difference to reduce the short-term cost gap between renewable H2 and fossil H2,” he says. “It’s a mixture of different funding instruments and policy tools at EU level and national level. Like the proposed targets in the revised Renewable Energy Directive, where the European Commission has proposed a target for the use of renewable hydrogen in industry... 50% of the hydrogen they consume [would have to be] renewable hydrogen. This is one way that we can incentivise a switch from grey to green.

“Having certainty that there will be demand means we will increase our capacities, which will lead to economies of scale and a subsequent reduction in capex costs. You cannot reduce cost from an empty factory.”

Cutting the cost of green hydrogen

Nel declared in January that its new factory will cut the cost of its electrolysers — ie, the machines that use an electric current to split water molecules into hydrogen and oxygen — by about 75%, helping the price of green hydrogen to fall to $1.50/kg by 2025.

“It is absolutely doable, provided of course we have the right regulatory framework to achieve volumes in production,” Løkke explains, pointing out that the US government has since adopted the same cost target. “Clear signals from policy makers, regulators and industry are key for us in terms of making the additional investments to increase capacity further.”

That $1.50/kg price would also require the cost of renewable energy to continue to fall.

“With the levelised cost of energy of wind and solar prices continuously coming down, renewable hydrogen will follow the same path, as electrical power constitutes 70-80% of hydrogen’s total cost.”

Løkke says that four factors will enable Nel to cut the cost of delivered electrolysers by 75% — automation and economies of scale at its new factory (which accounts for roughly half of the reduction); standardising module offerings to 20MW, 50MW, 100MW and 250MW; improved supply-chain procurement; and standardised design and pre-fabricated skids that reduce time and cost for commissioning and installation.

Use cases

The Norwegian tells Recharge that the biggest demand for electrolysers is currently coming from heavy industry, from hard-to-abate sectors such as “CO2-free steel, CO2-free ammonia, CO2-free methanol, etc” — rather than for more controversial uses such as transport and heating.

“We cannot achieve climate neutrality without hydrogen,” he explains, adding that the gas “can unlock the full potential of renewables, providing a means to flexibly transfer energy across sectors, time, and place”.

“You cannot make CO2-free steel with a battery, you need an H2 molecule to electrify steel production. The same goes for many other industry applications including mobility applications like shipping and aerospace. Hydrogen is key and we cannot decarbonise without it. That is why the future is bright for renewable hydrogen.”

He points out that Nel is already involved in projects focused on energy storage, heavy-duty trucks and steel plants, including the HyBrit project in Sweden, which is already producing steel using green hydrogen.

But while many independent analysts believe that hydrogen should not be used for heating buildings, Lokke is not so convinced, saying that it has potential in neighbourhoods close to industrial hubs — so-called “hydrogen valleys” — that will be both producing and using large amounts of H2.

“Regarding heating, we recently delivered a purchase order in Scotland for an electrolyser system that would heat 900 homes in a first phase,” he says. “Moving forward, as hydrogen valleys develop and as supply and demand increase, the case for the use of renewable H2 in heating could increase in these types of locations.”

And as a company that also manufactures hydrogen filling pumps, it is not surprising to hear Løkke talk up the potential of green hydrogen in transport.

“We are designing the station modules with a clear focus on TCO [total cost of ownership] for the final customer. From a cost of hydrogen at the pump of $5/kg, hydrogen will reach fossil parity and be competitive in most transport applications.”

The cost of hydrogen at the pump in Germany — the biggest market for fuel-cell vehicles in Europe — is currently €9.50/kg, according to the H2.live website.

Løkke also sees a bright future for green hydrogen in energy storage, despite the poor round-trip of efficiency of converting power to H2 and back again.

“Hydrogen can also help to balance the grid and store energy,” he says. “In 2020, an estimated €1.35bn [$1.52bn] worth of offshore wind energy was curtailed in Germany due to insufficient transmission grid capacity. In 2021, in the UK, 2.5TWh were curtailed at a cost of £172m ($227m) — that’s taxpayers’ money.

“So we need a clearer framework there to help the business model develop. This would be a win-win for all stakeholders: consumers, governments and industry.”

Japan's first offshore solar farm to feed robot battery-mule boats with power for Tokyo

Consortium plans futuristic energy system for Japanese capital under cutting-edge technologies programme

Source: Recharge News | By Andrew Lee

Japan’s first offshore floating solar array aims to generate power in Tokyo Bay that can then be stored and shipped back to shore in batteries by drone sailing vessels, said a group planning the ambitious project.

Dutch-Norwegian floating PV pioneer SolarDuck said its consortium with Tokyu Land Corporation and Everblue – a Japanese marine specialist – has been selected to build a demonstration plant as part of a Tokyo government plan to mobilise cutting-edge technologies for the city’s next 100 years.

SolarDuck – which is already planning arrays as large as 5MW in the North Sea off Europe – aims by Q1 2024 to deploy an 88kW floating solar system and mooring cables in the Tokyo Bay Area. The energy generated would be stored in batteries that would be transported back to shore by Everblue’s autonomous vessels for use in the power-hungry Japanese capital.

Few further details of the demonstrator such as PV capacity or timescale were given in a statement announcing the contract from the Tokyo government.

The partners said: “Tokyo, a major energy consumption area, is dependent on power transmission from the suburbs. The achievement of energy generation and marine transportation in the Bay Area will contribute to the realisation of a [unique] urban model.”

While deployment of floating PV on inland surfaces such as lakes and reservoirs is already booming, placing solar at sea presents a new level of challenge due to the harsh conditions facing equipment offshore.

China recently claimed a first when it linked two 0.5MW floating PV arrays with a single offshore wind turbine in the seas off Shandong province.

GE Turkey's 2022 Summary: building a bridge to the future with the sustainability principles

Source: GE Turkey | Author is some hard working grunt probably. The translator is Google.

December 30, 2022

Protecting the legacy of innovative approach left by Thomas Edison for 130 years, GE is always working for a better world. It is building a bridge to the future with the sustainability principles it has put at the center of its work for years. Thanks to the importance it attaches to diversity in business life and a free and open working environment, happy employees win. It always aims for the better with technology solutions that touch life.  GE has been building the future in Turkey for more than 70 years. As we prepare for a new year, we summarized the projects that GE Turkey implemented in 2022, the decisions it took and the signatures it signed. 

Here are the developments that marked 2022!

Turkey's Happiest Workplace

GE Turkey was deemed worthy of the "Turkey's Happiest Workplace" award in the Industrial Engineering category in the "Turkey's Happiest Workplaces Survey" conducted in collaboration with Happy Place to Work and Capital Magazine .

Environment, Health and Occupational Safety

This year, GE Turkey continued to work to ensure the safety of its employees and stakeholders. With the priority of environment and human; produced renewable technology solutions in energy, waste and natural resource management. Click for the interviews we conducted with our environment, health and safety employees .

First Step in My Career

This year , GE collaborated with the Contemporary Life Support Association for the "First Step in My Career" project . With the project, 60 girls and 15 boys studying in various cities of Turkey; An 8-week training that guided a total of 75 university students and mentoring was provided to professionals of the near future.

basilisk

Hayra Alamet – Şahmeran 34 exhibition , sponsored by GE HealthCare , brought together different artists and also made an important initiative that will contribute to the future of girls.

The Rise of Artificial Intelligence

GE HealthCare and Bayındır Health Group signed an agreement to test three applications based on artificial intelligence. Doctors in the radiology and emergency departments of Bayındır Söğütözü Hospital in Ankara, using Edison Open AI Orchestrator and other artificial intelligence applications offered by GE HealthCare and Lunit , present clinical images obtained from chest X-ray and mammography examinations with artificial intelligence supported findings and explanations. will review.

Three Separate Companies

As GE builds the future, it will continue as three separate companies. Firstly; GE HealthCare will leave early in the new year , followed by GE Vernova in early 2024 , and finally GE Aerospace to begin more focused work in their respective fields.

It Begins With Enlightenment

GE HealthCare said “Everything Begins with Enlightenment” in Turkey Breast Cancer Awareness Month and illuminated Atatürk Cultural Center with pink light for three days. Within the scope of the project, “illuminating” seminars were held to raise awareness about breast cancer.

From the Roots to the Future with Our Power

The 7th GE Turkey Women Employee Network Summit, where we have been listening to the experiences and inspiring speeches of successful leaders for years, took place this year. Inspired by GE 's deep-rooted past, saying “From the Roots to the Future with Our Strength” , the GE Women Turkey Women Employee Network Summit was filled with valuable speakers.

By the Power of the Wind

Upon the order of Poland's largest energy company PGE, Poland's largest generator transformers started to be produced at the Gebze Power Transformers Factory. The 830 MVA generator transformers, which will equip the Dolna Odra Power Plant and provide the highest technical efficiency in electricity generation, will deliver electricity to hundreds of thousands of households.

Our Future Face

In cooperation with the GE Turkey Women Employee Network and the Association for Supporting Contemporary Life , young people hosted the STEM event by saying “ Our Future Face ” to train the talents of the future and to increase the representation of women, who are few in number in working life, in technical roles.

Koch Industries’ Bet on Batteries

The company is plugging $30 million into a start-up co-founded by one of Silicon Valley’s favorite scientists.

Source: New York Times | By Andrew Ross Sorkin, Jason Karaian, Vivian Giang, Stephen Gandel, Lauren Hirsch, Ephrat Livni, Anna Schaverien and David F. Gallagher

April 6, 2022

Exclusive: New funds for an in-demand Silicon Valley scientist

Charles Koch — the C.E.O. of Koch Industries, the sprawling energy and commodities conglomerate — has funded conservative groups that raise doubts about climate change, part of the considerable political influence that his family fortune wields. Over the past few years, Koch has also been a big investor in batteries — a key technology in the global effort to cut carbon emissions.

An arm of Koch Industries has been betting that the fast-growing electric vehicle industry will generate vast demand for better batteries. Its list of investments includes Aspen Aerogels, Eos Energy Enterprises, Standard Lithium and, now, Blue Current, a start-up helmed by one of Silicon Valley’s favorite scientists, Joseph DeSimone. Koch Strategic Platforms is investing $30 million in Blue Current, which it will use to build a pilot and take it to production, DealBook is first to report.

“We are going to need a lot of batteries,” Elon Musk said last year at a Tesla event. Wood Mackenzie estimates that 18 percent of new cars sold will be electric by 2030, far outstripping current battery output. Battery manufacturing is dominated by companies like Tesla, Panasonic and LG Chem, but new players are emerging. Venture investors in the U.S. put $1.8 billion into the industry in 2021, far above any previous year, according to PitchBook.

DeSimone has helped Blue Current attract buzz. He is named in more than 200 patents, and left a long academic career in the sciences at the University of North Carolina at Chapel Hill and North Carolina State University to co-found Carbon, a 3-D manufacturing company, in 2013. (The company raised $680 million in private funding.) DeSimone stepped down as C.E.O. in 2019, becoming chairman of its board, and joined the Stanford faculty the next year. Since then, Silicon Valley has been wondering: What’s next?

Blue Current has worked in stealth mode since 2016, when DeSimone founded it with Nitash Balsara, a professor at U.C. Berkeley. The company is betting on solid-state silicon as a superior technology to batteries that rely on lithium and liquid electrolytes, which are highly flammable. Battery fires are a real problem for electric vehicles: Last year, General Motors had to replace the lithium-ion battery modules in 141,000 cars after some caught on fire. Solid-state batteries using either lithium or silicon are the next big thing for investors, but Blue Current says its silicon-based batteries are safer and have a particularly high energy density, meaning more charge in a smaller space.

Neither battery type is “ready for prime time yet,” said Venkat Srinivasan, the director of the Argonne National Laboratory’s Collaborative Center for Energy Storage Science, who has not directly evaluated Blue Current’s technology. A big question is whether the companies in this fast-growing industry can ramp up production enough to become commercially viable. Blue Current now has new funds from a high-profile investor to prove itself.

Andrew Ross Sorkin is a columnist and the founder and editor at large of DealBook. He is a co-anchor of CNBC’s "Squawk Box" and the author of “Too Big to Fail.” He is also a co-creator of the Showtime drama series "Billions." @andrewrsorkin • Facebook

Jason Karaian is the editor of DealBook, based in London. He joined The Times in 2020 from Quartz, where he was senior Europe correspondent and later global finance and economics editor. @jkaraian

Stephen Gandel is a news editor for DealBook. He was previously a senior reporter for CBS News, and a columnist at Bloomberg. He has covered Wall Street and financial firms for most of his career. @stephengandel

Lauren Hirsch joined the New York Times from CNBC in 2020, covering business, policy and mergers and acquisitions.  Ms. Hirsch studied comparative literature at Cornell University and has an M.B.A. from the Tuck School of Business at Dartmouth. @laurenshirsch

Ephrat Livni reports from Washington on the intersection of business and policy for DealBook. Previously, she was a senior reporter at Quartz, covering law and politics, and has practiced law in the public and private sectors.   @el72champs

Anna Schaverien covers news from Britain and Europe. She is based in London. @annaschav

Green power giant Iberdrola makes floating solar debut on Brazil paradise island

Spanish group enters fast-growing sector with array on Fernando de Noronha in nation's northeast

Source: Recharge News | By Andrew Lee

Global green power giant Iberdrola will leap into floating solar with a debut project on a Brazilian eco-paradise island.

The Spanish group will build the €2m ($2.1m) PV array on the waters of the Xaréu dam on the island of Fernando de Noronha, part of a volcanic archipelago off Brazil’s northeast.

The 630kWh array will provide about half the energy needs of Compesa, the utility that runs water and sewage on the island, a UNESCO World Natural Heritage Site, said Iberdrola, whose Neoenergia subsidiary will start building the project by the end of the year as part of a raft of initiatives there.

Iberdrola said the floating solar project will be its first globally and will allow the company to evaluate its wider potential.

Floating PV has rapidly gained traction around the world thanks to its ability to tap reservoirs, lakes and other water surfaces in areas where building on land is constrained or would cause environmental damage.

Wiring in floating solar arrays to existing hydropower reservoirs around the world could change the face of the global energy system by meeting nearly 50% of total electricity demand, according to a 2020 study by the US Department of Energy’s National Renewable Energy Laboratory (NREL).

Floating PV has more recently also started the journey offshore, with arrays designed to survive harsh conditions planned in Europe and Asia.

Vancouver company says it can demonstrate fusion technology at power plant scale by 2027

Source: CTV News Vancouver | by: Shannon Paterson

Updated Dec. 13, 2022 6:59 p.m. PST | Published Dec. 13, 2022 6:39 p.m. PST

On the heels of a major scientific breakthrough in fusion at a lab in California, the CEO of Vancouver-based General Fusion says his company is on track to demonstrate the real-world possibilities of the clean energy technology at the power plant level by the year 2027.

For the first time, scientists at Lawrence Livermore National Laboratory in California have achieved ignition, a fusion reaction that produced more energy than it took to create. General Fusion CEO Greg Twinney says it’s a huge step forward, as nuclear fusion has all the benefits of energy produced by nuclear fission, without any of the downsides.

“This is a scientific breakthrough, and what you need to be able to do now is to take this approach and translate it and repeat it on a regular basis in order to turn it in to a power plant, and that needs to be done in an economical and viable way long term. And that is where we come in,“ said Twinney.

His Vancouver-based company has 200 employees working with different types of fusion technology, aimed at producing clean, renewable energy.

“Our approach to fusion is a two-stage approach: You create the fuel mixture, plasma, and then you compress it. We do this in a similar way to a diesel engine, compressed fuel and air in a large cylinder, and what they do is increase the density and temperature to the point you get fusion reaction,” said Twinney. “We have designed an approach that has an end in mind of commercializing fusion, so putting it on the grid.”

He aims to demonstrate that technology at a power plant level by the year 2027, and have General Fusion’s first commercial power plant online in the early 2030s.

“We are headquartered here in Vancouver, this is where we have built our large-scale prototypes, large plasma injectors, compression systems and achieved these conditions in which we can now step out of a lab and into a full-scale power plant demonstration,” said Twinney.

He believes fusion will play a big part in renewable energy going forward, but said it needs government buy-in and investment.

“Funding is one of the biggest gates to unlocking fusion commercially,” said Twinney. “The more capital we have, the faster we are able to go. I do absolutely believe we can achieve net zero (carbon emissions) by 2050, but we are going to need to move quickly.”  

How a Quebec Lithium Mine May Help Make Electric Cars Affordable

The project also illustrates how difficult it is to get lithium out of the ground and break China’s dominance in processing the metal and turning it into batteries.

Source: New York Times | By Jack Ewing

Jack Ewing, who covers the global auto industry, reported from La Corne, Quebec.

• Sept. 20, 2022

About 350 miles northwest of Montreal, amid a vast pine forest, is a deep mining pit with walls of mottled rock. The pit has changed hands repeatedly and been mired in bankruptcy, but now it could help determine the future of electric vehicles.

The mine contains lithium, an indispensable ingredient in electric car batteries that is in short supply. If it opens on schedule early next year, it will be the second North American source of that metal, offering hope that badly needed raw materials can be extracted and refined close to Canadian, U.S. and Mexican auto factories, in line with Biden administration policies that aim to break China’s dominance of the battery supply chain.

Having more mines will also help contain the price of lithium, which has soared fivefold since mid-2021, pushing the cost of electric vehicles so high that they are out of reach for many drivers. The average new electric car in the United States costs about $66,000, just a few thousand dollars short of the median household income last year.

But the mine outside La Corne, operated by Sayona Mining, an Australian company, also illustrates the many hurdles that must be overcome to produce and process the materials needed to wean automobiles from fossil fuels. The mine has had several owners, and some of them filed for bankruptcy. As a result, some analysts and investors warn that many mines being developed now may never be viable.

Dozens of lithium mines are in various stages of development in Canada and the United States. Canada has made it a mission to become a major source of raw materials and components for electric vehicles. But most of these projects are years away from production. Even if they are able to raise the billions of dollars needed to get going, there is no guarantee they will yield enough lithium to meet the continent’s needs.

Amid a vast pine forest in Quebec sits a deep mining pit with walls of mottled rock. The rock contains lithium, an indispensable ingredient in electric car batteries that is in short supply.

Elon Musk, Tesla’s chief executive, said in July that being a lithium supplier was a “license to print money.” But it is also a risky, volatile business. Ore buried deep in the earth may have insufficient concentrations of lithium to be profitable. Opposition from environmental groups or nearby residents can delay or kill projects.

Mines tend to be in remote locations. By industry standards, Sayona’s mine, which is at the end of a 12-mile gravel road, is just around the corner. Many other projects are far more inaccessible.

After the price of lithium fell by half from 2017 to 2020, the mine’s previous owner, the Chinese battery maker CATL, shut down operations and sought protection from creditors for the subsidiary that owned the property. Sayona, working with Piedmont Lithium, a lithium mining and processing company based in Belmont, N.C., bought the operation last year.

Sayona site sits at the end of a 12-mile gravel road about 350 miles northwest of Montreal.

Some investors believe the hype around lithium is overblown and have been betting against mining companies. They believe that some of the companies lack the expertise to blast ore, haul it out of the earth and separate the lithium from the surrounding rock. Lithium projects often suffer delays and cost overruns.

The risk is reflected in the gyrations of Sayona shares traded on the Australian Securities Exchange in Sydney. They peaked at 36 Australian cents (24 U.S. cents) in April, plunged to 13 cents in June and have recently traded at around 28 cents.

“Those of us in the industry are quite confident that lithium will be in short supply for the next decade,” said Keith Phillips, chief executive of Piedmont Lithium, which owns 25 percent of the Sayona’s Quebec project. He added, “Others are taking a contrarian view.”

For many people in government and the auto industry, the main concern is whether there will be enough lithium to meet soaring demand for electric vehicles.

The Inflation Reduction Act, which President Biden signed in August, has raised the stakes for the auto industry. To qualify for several incentives and subsidies in the law, which go to car buyers and automakers and are worth a total of $10,000 or more per electric vehicle, battery makers must use raw materials from North America or a country with which the United States has a trade agreement.

Lithium is the lightest known metal; its ability to store energy makes it attractive for batteries.

The world will also need more refineries, the plants where raw lithium is processed into a concentrated form of the metal that goes into batteries. Most lithium is processed in China, and Piedmont and other companies plan to build refineries in the United States. But lithium processing requires expertise that is in short supply, said Eric Norris, president of lithium at Albemarle, a mining and processing company in Charlotte, N.C.

Lithium is the lightest known metal, and its ability to store energy makes it attractive for batteries. But lithium deposits come embedded in other metals and minerals. That is why extracting lithium can be incredibly difficult.

The mining industry “has not honed its ability, broadly speaking, to build conversion capacity repeatedly and consistently,” Mr. Norris said, noting that even his company, which has extensive experience, has suffered delays building processing plants.

Albemarle operates the only active lithium mine in the United States, in Silver Peak, Nev., where the metal is extracted from brine, a liquid found beneath the ground. Some Tesla batteries contain lithium from Nevada, but the site’s total annual output is enough for about 80,000 vehicles. Americans bought 370,000 battery-powered cars in the first six months of 2022, according to Kelley Blue Book, and sales are rising fast.

The mine outside La Corne has traded hands several times; some of the businesses that had owned it filed for bankruptcy.

Albemarle also produces lithium in Chile and Australia. The company is working to reopen a lithium mine in Kings Mountain, N.C., and plans to build a refinery in the Southeast.

Even those large projects will not be enough to satisfy demand as California and other states move to ban internal combustion engines. “It’s going to take everything we can do and our competitors can do over the next five years to keep up,” Mr. Norris said.

One of the first things that Sayona had to do when it took over the La Corne mine was pump out water that had filled the pit, exposing terraced walls of dark and pale stone from previous excavations. Lighter rock contains lithium.

After being blasted loose and crushed, the rock is processed in several stages to remove waste material. A short drive from the mine, inside a large building with walls of corrugated blue metal, a laser scanner uses jets of compressed air to separate light-colored lithium ore. The ore is then refined in vats filled with detergent and water, where the lithium floats to the surface and is skimmed away.

The end product looks like fine white sand but it is still only about 6 percent lithium. The rest includes aluminum, silicon and other substances. The material is sent to refineries, most of them in China, to be further purified.

Yves Desrosiers, an engineer and a senior adviser at Sayona, began working at the La Corne mine in 2012. During a tour, he expressed satisfaction at what he said were improvements made by Sayona and Piedmont. Those include better control of dust, and a plan to restore the site once the lithium runs out in a few decades.

“The productivity will be a lot better because we are correcting everything,” Mr. Desrosiers said. In a few years, the company plans to upgrade the facility to produce lithium carbonate, which contains a much higher concentration of lithium than the raw metal extracted from the ground.

The operation will get its electricity from Quebec’s abundant hydropower plants, and will use only recycled water in the separation process, Mr. Desrosiers said. Still, environmental activists are watching the project warily.

Long Point First Nation, an Indigenous group, wants to do its own environmental impact study of lithium mines that it says are on its ancestral territory.

Mining is a pillar of the Quebec economy, and the area around La Corne is populated with people whose livelihoods depend on extraction of iron, nickel, copper, zinc and other metals. There is an active gold mine near the largest city in the area, Val-d’Or, or Valley of Gold.

Mining “is our life,” said Sébastien D’Astous, a metallurgist turned politician who is the mayor of Amos, a small city north of La Corne. “Everybody knows, or has in the near family, people who work in mining or for contractors.”

Most people support the lithium mine, but a significant minority oppose it, Mr. D’Astous said. Opponents fear that another lithium mine being developed by Sayona in nearby La Motte, Quebec, could contaminate an underground river.

Rodrigue Turgeon, a local lawyer and program co-leader for MiningWatch Canada, a watchdog group, has pushed to make sure the Sayona mines undergo rigorous environmental reviews. Long Point First Nation, an Indigenous group that says the mines are on its ancestral territory, wants to conduct its own environmental impact study.

Sébastien Lemire, who represents the region around La Corne in the Canadian Parliament, said he wanted to make sure that the wealth created by lithium mining flowed to the people of Quebec rather than to outside investors.

Mr. Lemire praised activists for being “vigilant” about environmental standards, but he favors the mine and drives an electric car, a Chevrolet Bolt.

“If we don’t do it,” he said at a cafe in La Corne, “we’re missing the opportunity of the electrification of transport.”

Jack Ewing writes about business from New York, focusing on the auto industry and the transition to electric cars. He spent much of his career in Europe and is the author of “Faster, Higher, Farther," about the Volkswagen emissions scandal. @JackEwingNYT • Facebook

A version of this article appears in print on Sept. 20, 2022, Section A, Page 1 of the New York edition with the headline: Canadian Mine May Hold a Key To Electric Cars. Order Reprints | Today’s Paper | Subscribe

Hydrogen tax credit details: USA

Source: Recharge News | by Leigh Collins

The $433bn Inflation Reduction Act of 2022 creates a tax credit that would pay clean hydrogen producers up to $3 per kilogram (adjusted for inflation).

The size of the tax credits available to US clean hydrogen producers depends on the lifecycle greenhouse gas (GHG) emissions of each project — and more importantly, on how much staff are paid.

So the basic tax credit rate for “qualified clean hydrogen” is set at $0.60/kg, with a sliding scale depending on lifecycle emissions — measured in carbon dioxide-equivalent (CO2e) — of the H2 produced.

Hydrogen manufactured with less than 0.45kg of lifecycle CO2e emissions per kg of H2 would receive 100% of the credit, followed by 33.4% for 0.45-1.5kgCO2e/kgH2, 25% for 1.5-2.5kg and 20% for 2.5-4kg.

The lifecycle emissions would have to be verified “by an unrelated third party”, and only projects that start construction before 2033 would qualify.

However, the wage requirement in the new bill seems to be the most important part of the deal — multiplying the size of the tax credit by a factor of five.

Producers would be eligible for this boost if they ensure “that any laborers and mechanics employed by contractors and subcontractors in the construction of such facility… shall be paid wages at rates not less than the prevailing rates for construction, alteration, or repair of a similar character in the locality in which such facility is located as most recently determined by the Secretary of Labor”.

Importantly, these lifecycle emissions are calculated from “well to gate” — in other words, they would include upstream methane emissions in the production of blue hydrogen (which is made from natural gas with incomplete carbon capture and storage).

Also, the IRA states that blue hydrogen projects would be ineligible for H2 tax credits if they already receive federal tax credits for carbon capture and storage — but green hydrogen projects would also be allowed to receive renewable energy tax credits valued at $30/MWh in addition to the hydrogen ones.

'This will set the bar' | All eyes on California for historic first US floating wind auction

ANALYSIS | As bumper 43 applicants line up, experts say milestone round is test for industry's risk appetite while industrialisation holds key to long term success

5 December 2022 16:28 GMT UPDATED  5 December 2022 17:05 GMT

Source: Recharge News | By Tim Ferry

The US’ flagship west coast deepwater wind auction set to kick off tomorrow (6 December) is the nation’s most eagerly anticipated seabed leasing round since the New York Bight spurred a $4bn-plus bidding bonanza, and marks the opening of a whole new frontier for the global floating sector.

The US government and the state of California will spur at least 4.6GW – and likely far more – of new capacity and a multibillion dollar investment wave, playing a huge role in the state’s massive climate and renewable energy ambitions that include a near term target of 2-5GW by 2030 and 25GW by 2045.

Five lease zones spread across two separate wind energy areas (WEA) off Morro Bay in central California and Humboldt County in the north are to come under the hammer (see graphic at foot). The WEAs sprawl over some 373,000 acres of Pacific deepwater and hold a wind resource expected by the Bureau of Ocean Energy (BOEM), the lead regulator of energy development in federal waters, to generate enough clean power for 1.6 million homes.

The auction has attracted a bumper 43 applicants that includes international stalwarts, American newbies, and joint ventures across technology and project developers.

The leasing round begins 6 December at 0700 Pacific Standard Time (1000 Eastern Standard Time), with BOEM anticipating it may extend over several days. Bids start at $6m and provisional winners will be announced at its conclusion, but the results may take several weeks before being certified.

But will that huge demand lead to a feeding frenzy such as was seen for fixed-bottom capacity in the New York Bight, where bids totalled $4.37bn in February this year? Not necessarily, according to some expert commentators.

“Prices tend to be higher in states that have actual offshore wind mandates than in states where they're just supporting it,” Walt Musial, National Renewable Energy Laboratory (NREL)’s head of offshore wind energy research, told Recharge.

New York and New Jersey, the two US states facing the New York Bight, have some of the nation’s most aggressive legal targets. “In California, we don’t see that mandate,” said Musial.

California’s mid-century floating goal leads the nation but is not legally mandated. The state does have aggressive decarbonisation mandates of 40% reduction in greenhouse gas emissions off 1990 baselines by 2030, and economy-wide carbon neutrality by 2045, but is technologically agnostic.

The state leads the US with 27GW of utility and residential solar, but this poses grid balancing challenges.

Musial said California understands that floating wind is going to be needed, “but to what degree is still in question.”

The state also lacks a clear pathway to market, as it doesn’t have a central authority capable of organising procurement.

“These first few leases will set a bar for where things go,” said Musial.

Diverse range of bidders

California’s floating auction has seen an unprecedented range of bidders, from industry stalwarts Orsted and Avangrid to oil supermajors TotalEnergies and BP and local energy consortiums new to the sector, such as Redwood Coast Energy Authority (see panel).

This “reflects both confidence in the direction of national and state energy goals [and] the knowledge that offshore wind has to be a significant part of the solution,” said Theodore Paradise, chief policy and legal officer in the US for Swedish floating wind developer Hexicon, which is also a qualified bidder.

Floating wind “is the perfect complement to solar to generate clean, reliable baseload power”, Jonah Margulis, senior vice president for offshore wind at Mainstream Renewables, told Recharge.

Scott Urquhart, CEO of research consultancy Aegir Insights, told Recharge: “Getting one of the first leases gives you a good foothold and positions you for many future options that might come your way.”

The auction is heavily focused on delivering local economic benefits, with 10% of the bid value available as community benefit agreements and 20% towards supply chain and workforce development, and those successful in obtaining lease options will need to invest in significant supply chain plans as well as bonuses directly to affected communities.

Port, transmission, and supply chain bottlenecks

California needs substantial supply chain and port investment, without which successful leaseholders will face myriad challenges advancing their projects.

Marshalling ports are “absolutely necessary for projects to get built,” said Musial, but Morro Bay has no readily available port nearby, with the only harbour actively developing a floating wind programme at Humboldt Bay, nearly 500 miles (800km) away.

Joshua Singer, lead on offshore wind ports for engineering consultancy Moffat & Nichol, told a recent conference, “There are no other ports on southern California that can be readied in time.”

Morro Bay’s three leases hold around a gigawatt each, and any port capacity built in the vicinity would need to be shared, adding to the risk, said Musial.

CALIFORNIA FLOATING WIND AUCTION QUALIFIED BIDDERS

547 Energy

AEUG Offshore

Algonquin Power Fund (America)

Arevia Power

Avangrid Renewables

BP US Offshore Wind Energy

California North Floating

California Offshore Wind Development

California South Floating

Castle Wind

Central California Offshore Wind

Cademo Corporation

Cierco Project Corporation

Clearway Renew

Corio OSW Investments

CPV Offshore Wind

EDF Renewables Development

EDPR Offshore North America

Equinor Wind US

Ferrovial Energy US

GW Offshore Wind

Hexicon USA

Ideol USA

Invenergy California Offshore

JERA Renewables NA

Marubeni Power International

Mission Floating Wind

Northcoast Floating Wind

Northland Power America

Orsted North America

Pacific Moon Offshore Wind

Pacific Offshore Wind

Redwood Coast Energy Authority (RCEA)

Redwood Coast Offshore Wind

RWE Renewables Development

RWE Offshore Wind Holdings

Seaglass Offshore Wind I

Seaglass Offshore Wind II

Shell New Energies US

SSE Renewable North America Offshore Wind

TotalEnergies Renewables USA

US Mainstream Renewable Power

Humboldt WEA, conversely, has existing transmission infrastructure to handle only some 150MW of offshore wind power, a tenth of its 1.5GW capacity potential.

Floating wind plant in northern California would require $5.3bn-$8bn in high-voltage transmission lines, according to the California independent system operator (Caiso), compared to only a single, 500kV substation for around $110m for the central coast.

“They're probably going to need more lease areas” to drive investment in the grid, Musial noted.

Supply chain investment is another question for the industry. The state has large-scale industrial ports at Long Beach and Los Angeles, but these are already bursting at the seams with logistics activity.

Building supply chain capacity instead of shipping components in from Asia or the US east coast could drive mass investment and jobs creation.

American Job Project sees GDP impacts from construction alone driving $16.2bn to $39.7bn in California, while the University of Southern California’s Schwarzenegger Institute estimates job gains from developing 10GW by 2040 totalling up to 195,000 job-years.

'Global epicentre'

Jason Folsom, vice president for renewables at Aker Solutions, told the Recharge Summit event in Washington, DC in November that California could become “the global epicentre for floating wind”.

Still, the industry’s success will depend on cost reductions that are being challenged by surging inflation, rising interest rates, and relentless supply chain disruptions.

The Biden administration’s Floating Wind shot aims to not only see 15GW of capacity in deep waters off US coastlines but the levelised cost of energy (LCOE) slashed by 70% in that same time frame.

Musial said cost reductions depend on large-scale industrialisation on the same turbine platform.

“The industry needs to mature the platform that they’ve developed at the 15MW scale and optimise and industrialise around that point,” he said.

“We can gain huge cost reductions just through the industrialisation of one specific platform, the standardisation of those parts in serial production, and the learning that goes on at those levels,” he said.

European electricity market: "We need a reform to stimulate low-carbon investments and guarantee supply"

Source: LeMonde, The world | by some french dudes? and translated by Google

Posted january 6, 2023 at 06:00, updated at 06:00

Due to soaring electricity prices, several opposition representatives, from the Rassemblement national to La France insoumise, including the Republicans, are calling for an exit from the European electricity market to lower consumer bills. , citing the example of Spain and Portugal. While qualifying this market as "badly done for a very long time" , Emmanuel Macron promised, Thursday, January 5, for the second half of 2023 "a reform of the electricity market so that it depends [on] production costs" .

How does this market work? As electricity cannot be stored, the principle of the European system consists in guaranteeing the balance between supply and demand for electricity on a European scale, by calling on the least expensive means of production as a priority. When it is no longer enough, other means are brought in, always favoring the least expensive. But the market price depends on the cost of production of the last plant to come into operation, which is often gas-fired. The more the gas plants are in demand, the higher the market price. This is the case this winter, due to the shutdown of many French nuclear reactors and the war in Ukraine, which has caused gas prices to soar.

Several European countries using a lot of gas to produce electricity, such as Germany and Italy, the European electricity market, which sets a single price regardless of the means of production, may therefore seem unfair for a country like France which has a large nuclear fleet .

But is the European market solely responsible for the current price spike? Are Spain and Portugal really out of it? Would France have an interest in following their example? Interviewed by Le Monde , Nicolas Goldberg, expert at Colombus Consulting, delivers his analysis.

What is wrong with the European market?

Many of the reproaches made to the European market are in fact the result of a misunderstanding. What some politicians are saying is that electricity prices are pegged to gas prices because of the Germans and that's why their prices are high, but that's not true. This system has one virtue, which is that the balance between supply and demand is achieved at the lowest possible cost. Each producer has an interest in offering the lowest price in order to receive the marginal tariff [the difference between the cost of production and the tariff for the last kilowatt-hour produced]. This can, of course, generate excess profits, but they are currently taxed and this taxation feeds the tariff shields. The reproaches of political leaders are therefore unjustified and the Germans have nothing to do with it.

On the other hand, what can be criticized for this system is that it encourages the sizing of production capacities as accurately as possible. Today, France sometimes imports electricity when it could produce it, quite simply because it is cheaper. The European market guarantees this ability to import at the best price, which is a good thing for consumers. But that does not encourage us to invest in production capacities, which reduces our room for manoeuvre. When you encounter a problem such as corrosion of nuclear facilities or gas supply difficulties, there is a risk of a shortage, as we can see today. This is the reason why opposition leaders who do not understand this functioning or want to use it for political ends are asking for a way out, citing, wrongly, the example of Spain and Portugal.

Precisely, have these countries really left the European electricity market?

No, that's completely wrong. They remain fully integrated into it, but have obtained a temporary exemption which allows them to cap the wholesale price of gas and reduce consumer bills by only 10% to 15% because the cost of the device is re-invoiced to consumers. But this is also what other Member States of the European Union [EU] do indirectly with tariff shields financed by taxing excess profits . The French government tells us of a saving of 20%. It is therefore more effective than what Spain is doing, without the perverse effects .

One country has indeed left the European market, it is the United Kingdom. It is still connected to the European network and continues to import electricity, but negotiates it over the counter and the tariffs are necessarily higher than if it had remained there and decoupled from the rest of the EU. Strangely, the political leaders who want to get out of it do not cite this example...

So France would have no interest in leaving it?

The answer is clearly no, for two reasons. The first is that it lacks electricity today, which has not escaped anyone. However, the European market makes it possible to import massively at the best price, a price harmonized at European level. When France is an exporter, on the other hand, he guarantees us that there will always be outlets, even when our nuclear power stations are producing at full capacity, because this electricity is cheaper than fossil fuels and France can use these interconnections to export. In this case, we don't hear anyone saying that we have to get out of it.

This European market therefore has a double benefit: when we have overcapacity, it allows us to export at very good prices and bring in foreign currency; when we are short of capacity, which is rather the case at the moment, our supply remains guaranteed at the best price. The interconnections have also shown their good functioning this winter.

Should it, despite everything, be reformed?

I think it is necessary. The market was developed in a logic of great liberalisation, at a time – the 1990s – when the fight against climate change was not the primary concern and when the European electricity system was very overcapacity. It contributed to the closure of means of production, in particular coal-fired power stations, but did not encourage investment. This system is myopic. It does not encourage looking at things in the long term.

We need a reform to stimulate investment in low-carbon production and guarantee security of supply, which would also limit the effects of speculation. In normal times, the European market protects us from it, because there is no reason to speculate when security is guaranteed; this was not the case this summer, when the risk of a shortage emerged, which opened the way to speculation. Among the avenues for reform, there is therefore that of imposing prudential rules on electricity suppliers so that they hedge themselves in the long term and are less subject to the ups and downs of the market.

Ice or Molten Salt, Not Batteries, to Store Energy

Source: New York Times | By Matthew L. Wald

• April 21, 2014

WASHINGTON — ENERGY storage is crucial to transforming the electric grid into a clean, sustainable, low-emissions system, the experts say. And it’s happening already, just not the way most consumers would expect.

The simplest idea for storage — charging up batteries at night when there is a lot of wind energy and not much demand for it, or at midday when the sun is bright — is years from being feasible, according to the experts.

The reason? It costs hundreds of dollars to store a kilowatt-hour of energy in a battery, while nationally the average retail price of a kilowatt-hour is about 11 cents. On the wholesale market, even buying low at off-peak periods and selling high could earn a battery owner perhaps 25 or 30 cents for each $400 or so invested. For that kind of transaction, “storage is not profitable,” said Jay Apt, executive director of the Carnegie Mellon Electricity Industry Center.

Prices would have to fall by 90 percent, from the current range of $300 to $500 per kilowatt-hour of capacity down to $30 to $50, he said. Instead, electric companies and some users of commercial power are adopting storage in forms that many people would not recognize as batteries — big containers of ice in building basements, or vast tanks of molten salt,  for example. And where plain old batteries that store actual electricity are being used on the power grid, they do very subtle, high-value jobs, like keeping the alternating current system in the proper rhythm, or smoothing out the flow of energy from wind farms that are prone to start and stop suddenly.

On the horizon is an exotic future of battery installations in places with plenty of conventional and renewable capacity that will need a bridge from daytime solar power. California anticipates that need in a few years, when solar power wanes at sunset, but natural gas plants are unable to awake fast enough from their afternoon nap, a problem the utility industry calls “ramping.”  Batteries will be needed to let the natural gas system start up early and supplement electricity supplies at twilight.

The storage field is so new that even executives in the energy business have trouble knowing how to think about it.

Take, for example, the strange tale of Dauren Kilish, an executive of AES Energy Storage, a company in Northern Virginia. Mr. Kilish’s firm set out to build a 40-megawatt battery in Texas, comprising several truck trailers. That amount of power would run about 4,000 window air-conditioners on a hot day or absorb about half the output of a small power plant running on natural gas.

Mr. Kilish called the grid operator to register the battery as an asset on the grid, since the battery was designed to be charged or discharged at the operator’s command. The grid keeps track of each generator as a resource, but also keeps track of businesses and can absorb extra energy when the system has a surplus.

So in which category  should it be registered? asked Mr. Kilish. Both, said the system operator, as a 40-megawatt source of supply and as a 40-megawatt source of load. AES said the system operator told the company to list the battery as an 80-megawatt resource.

AES also operates a big battery bank at the center of a wind farm in West Virginia. But it does not do what a consumer might expect; that is, storing energy from wind that blows mostly at night to meet heavier demand during the day when market prices are higher. Instead, on days when the wind is variable, it absorbs extra energy when a gust comes through, and pushes the energy back into the grid when the wind machines are suddenly calmed, to smooth out the variation in the farm’s output. It is far too small to store meaningful amounts from nighttime until daytime.

The value of storage, according to AES, is to add flexibility to the system.

But the way to store bulk amounts of energy for the grid lately is with cold or heat, as ice or molten salt. Hundreds of buildings now use their air-conditioning systems to freeze water into ice in the middle of the night,  taking advantage of low outdoor temperatures to help do the job. During the day, they melt the ice to cool the air.

In the Arizona desert, a major new solar plant uses the sun’s heat to warm sodium into a hot liquid. When the sun goes down, the sodium is piped into a steam generator, giving off its heat to boil water, which is used to spin a turbine and make electricity. The builders say using batteries would have made the costs many times higher.

A Houston company, TAS Energy, stores energy as cold. It chills water at night, and during the hot Texas summer, uses the cold water in a device like a radiator, to cool incoming air that is sent to a plant burning natural gas. When the incoming air is cooler, it is denser, so more of it fits into the combustion chamber, and power output is higher. The effect is to use nighttime energy to increase capacity in the hot afternoon.

Nearly all of these technologies lose energy on the way; that is, their round-trip efficiency, the ratio of energy put in to energy taken out, is well under 100 percent. But Darrell Hayslip, the chairman of the Energy Storage Association, said energy efficiency was not the point: dollar efficiency was. “You can’t really measure round-trip efficiency; it’s a function of economics,” he said. “If the charging electricity costs $2 vs. $20 for the electricity discharged, then it’s got greater round-trip efficiency.”

Mr. Hayslip’s trade group is 20 years old, but recently changed its name to “energy storage” from “electricity storage,” to better account for the variety of forms in which energy is being stored.

A version of this article appears in print on April 22, 2014, Section F, Page 7 of the New York edition with the headline: Ice or Molten Salt, Not Batteries, to Store Energy. Order Reprints | Today’s Paper | Subscribe