JinkoSolar released a suite of new products under the “Eagle” name this week during the virtual Solar Power International tradeshow. Both high-power solar panels and energy storage systems are on display for the first time by the world’s largest solar panel manufacturer.

New panels include:

• Eagle 60HM G2: 330-W half-cell mono PERC module
• Eagle 72HM G2: 410-W half-cell mono PERC module
• Eagle 72HM G3: 405-W bifacial half-cell mono PERC module
• Eagle 66TR G4: 390-W tiling-ribbon mono module (using larger M10 wafers)
• Eagle 78TR G4b: 475-W tiling-ribbon bifacial mono module (using larger M10 wafers)

This is the first time Jinko’s tiling-ribbon technology has been used in panels released to the U.S. market. The company has similar modules under the “Tiger” name in China.

“Jinko’s Tiling Ribbon (TR) technology is different from shingled modules. There is some overlap of cells that is facilitated by the tiling ribbon,” explained Vikash Venkataramana, director of technical service and product management for JinkoSolar to Solar Power World earlier this year. “The ribbon is designed so that it can be positioned between the overlapping cells to eliminate any direct contact between the overlapping cells, removing any concern of mechanical stress. Special encapsulants are also used in the module to reduce mechanical stress.”

Most interestingly is the release of lithium batteries and energy storage systems by the predominantly solar panel-focused company.

The Eagle RS1 is a 8-kW/19.2-kWh AC-coupled energy storage system. It is stackable up to 28.8 kWh and 38.4 kWh. Its lithium-iron phosphate (LFP) technology is popular among the residential market. The Eagle RS1 has a 6,000-cycle-life and is outdoor-rated. The residential system is available for orders beginning in December 2020.

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The SCC asked stakeholders to address a series of questions and submit suggested text for the regulation. The comment period closed July 29, but the commission granted an extension until Aug. 14 for submission of suggested regulatory text.

SCC requested comments on several issues, including:

• Should the regulation apply to non-utility storage?
• What interim storage targets should the commission set for APCo and Dominion?
• What behind-the-meter, non-wire alternatives, and peak demand reduction programs should the regulation include?
• What updates to existing utility planning and utility procurement rules should the commission adopt?
• What competitive behind-the-meter incentives and competitive solicitation-related programs and mechanisms should the regulation include?
• Should the regulations mandate or limit the deployment of certain types of storage?
• Should the commission establish definitions in its regulations for “energy storage,” “energy storage capacity,” “energy storage facilities,” “energy storage project,” and “energy storage resources;” and should each term have its own regulation?

“Our priorities are to provide safe, reliable and affordable electric service to our customers and more renewable energy and energy storage is an important part of that,” a spokesperson for Dominion Energy Virginia said in an email.

APCo and Dominion submitted a joint comment, suggesting interim storage targets for themselves. APCo suggested adding 25 MW by the end of 2025, an additional 125 MW by 2030 and another 250 MW by 2035. Dominion suggested adding 250 MW by the end of 2025, an additional 950 MW by 2030, and another 1,500 MW by 2035.

The companies also asked that SCC set “high-level parameters” for most requirements, not create regulations for every term defined in the regulation, and asked that SCC’s regulations apply both to utility and non-utility storage projects.

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An optimal power system portfolio for the US state of California that would drive the world’s fifth largest economy towards greenhouse gas reduction goals for 2030 and then to zero carbon by 2040, includes 1GW of long duration energy storage, an analyst has highlighted.

The roadmap includes around 25GW of new renewable generation, our sister site PV Tech reported last week, including an interim pathway to reduce greenhouse gas (GHG) emissions from the electric sector down to 46 million metric tonnes (MMT) by 2030, as it then scales towards a mandated target of supplying “100% of retail electricity sales with renewable and zero-carbon resources by 2045”.

Load-serving entities (LSEs) in the state must put forward individual integrated resource plans (IRPs) in order to meet either the 46 million metric tonne target as baseline or a more stringent 38 MMT target within 10 years.

The optimal portfolios laid out in the CPUC Proposed Decision on “2019-2020 Electric resource portfolios to inform integrated resource plans and transmission planning,” include a “large amount of new solar, wind, and battery storage resources, as well as long-duration storage and out-of-state wind on new transmission”.

Various commentators and experts have identified that the utility IRPs – which essentially lay out how utilities will invest for the benefit of their ratepayers over medium to long-term periods – across the US will be vital to the adoption of renewable energy, and therefore of energy storage as a key set of technologies in integrating that new capacity.

Interim target includes reaching 60% renewables by 2030
Alex Eller, senior research analyst at Navigant Research’s energy storage practice, said that the plan recently put forward in a Proposed Decision in February and then adopted in mid-March by regulator California Public Utilities Commission (CPUC), “identifies the specific need for 1GW of long duration energy storage by 2026”.

In a blog for his company’s site, Eller pointed out that market signals favouring deployment of long duration energy storage, which generally starts out more expensive per-kilowatt hour than shorter duration systems but scale as project storage duration requirements increase.

“California has a relatively high penetration of renewable energy on its grid and some of the most ambitious goals in the world. The need for LDES has always been on the horizon in the state, which has been a hotbed of new energy storage technology and project development,” Navigant’s Alex Eller wrote.

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Kyocera has officially launched a residential energy storage system using an advanced manufacturing process that supplier 24M claims can reduce some of the key costs of lithium battery making by as much as 50%.

The Japanese company’s new product, Enerezza, is aimed at the booming market in its homeland and is available in 5kWh, 10kWh and 15kWh capacities. Kyocera began pilot production of battery cells and systems in June using 24M’s proprietary production process, which uses electrodes typically 3-5 times thicker than in other lithium-ion batteries.

“Full-scale mass production” is set to begin in autumn 2020, while prior interviews between this site and 24M hinted at initial production volumes of around 100MW. A release sent to Japanese press by Kyocera in October 2019 claimed that initial output would be at around 20,000 residential Enerezza units annually.

Kyocera said previously that the units will address two key market segments: At-home self-consumption of solar PV-generated electricity in Japan (feed-in tariffs (FITs) awarded since 2009 expired last year while the more generous tariffs brought in since 2013 are declining rapidly), as well as being used for backup power.

An Energy-Storage.news interview last year with UK company Moixa, which supplies its GridShare software to battery energy storage units made and sold by Japanese company Itochu, found that the latter company – one among many providers in the domestic market – is selling around 10MWh of residential systems every month.

The need for backup power in a country which experiences as much as 10% of the world’s seismic activity each year, means that battery systems sold in Japan tend to be larger on average than devices sold purely for solar load shifting and self-consumption in other parts of the world.

‘A disruptor to the entrenched lithium-ion cell design and manufacturing process’

Meanwhile US-headquartered 24M has been developing its battery manufacturing process for commercialisation for some time. Back in 2015, this site wrote that the company was pursuing 50% cost savings over existing li-ion technology and aimed to hit US$100 per kWh cost of production by 2020. Analyst Lilia Xie at Lux Research blogged that 24M, spun out of A123 Systems in 2010, was “positioning itself as a disruptor to the entrenched lithium-ion (Li-ion) cell design and manufacturing process”. In March 2019, the company also claimed it had achieved energy densities exceeding 350Wh per kg.

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A unique project combining large-scale capacities of solar PV and concentrated solar thermal (CST) will be able to deliver firm power through the use of a pioneering thermal energy storage plant.

Last week, Australian firm 1414 Degrees (14D) said it would acquire SolarReserve Australia II Pty Ltd, which owns the aforementioned Aurora Solar Energy Project near Port Augusta in South Australia as well as two other solar sites in New South Wales.

14D will use the Aurora complex to pilot its pathfinding TESS-GRID thermal storage technology and deliver stable power to the grid. The storage system will gradually be built up to store and dispatch several thousand megawatt-hours, the firm said in a release.

Thermal Storage inventory

The thermal storage system would supply hours of dispatchable electricity with spinning reserve from its turbines and a range of frequency control ancillary services (FCAS) to support grid stability. The TESS-GRID could also purchase and store electricity generated by other renewable energy projects on the region’s high voltage transmission network. This would strengthen its firming services and increase earnings from market arbitrage.

The company stores energy in molten silicon as latent heat, reaching 1414° Celcius, hence its name. Thus, heat stored by the TESS-GRID at the Aurora plant could power greenhouses and industry, while 14D is also considering production of hydrogen using the excess heat from its turbines.

14D’s emergence came after a TESS prototype was first demonstrated in 2016 and then scaled twenty times to commission a large electrically charged TESS in December 2018. The company then commissioned a biogas fired thermal energy storage system as a pilot plant at its first commercial site at SA Water’s Glenelg Wastewater Treatment Plant in May 2019.

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The Regional Municipality of York, Southern Ontario, Canada, will be the proving ground for a local electricity market, aimed at helping integrate distributed energy resources (DERs) into the grid.

Ontario’s Independent Electricity System Operator (IESO), is set to launch a demonstration of how solar panels, energy storage and customer-sited demand side response (DSR) connected to the distribution network can be used to drive down costs of the IESO’s transmission operations.

The IESO said just before the end of August that it will launch the project, which will in part help the network to “find affordable alternatives to building new transmission infrastructure,” as well as hopefully creating a competitive marketplace to help bring down consumer costs. Ontario’s Alectra Utilities and the government ministry Natural Resources Canada are supporting the IESO on the project.

“When we’re out talking to communities, one common theme we hear is a desire to have more choice in how their electricity needs are met,” Ontario IESO president of policy, engagement and innovation, Terry Young, said.

“This pilot will help us learn if we can enable that choice while also reducing costs for Ontarians.”

In common with similar, relatively small-scale trial and projects launched in Cornwall, England, in Australia and in Japan, the local electricity market seeks to leverage existing resources, for example by turning down customer demand for power from the grid through DSR or by storing energy in batteries generated from solar in the daytime to push into the grid at peak times.

“This project will help us better understand the potential of using distributed energy resources in place of traditional infrastructure by evaluating them in real-world applications,” Alectra Inc CEO and president Brian Bentz said.

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With the expected uptick in EV adoption over the next few years, companies around the world are looking for ways to repurpose used EV batteries that can have up to a decade of life left in them, and energy storage is one potential application.

Previous second-life projects often included EV manufacturers. In October, Nissan and EDF Energy announced a project that will combine used EV batteries with demand response capabilities developed by the U.K. energy company. Also in 2018, Wärtsilä and Hyundai Motor Group partnered on a project to develop uses for second-life EV batteries in Germany. Hyundai estimates that in 2025, there will be 29 GWh of second-life EV batteries available.

A focus area of the agreement between Cummins and UC San Diego will be stationary energy storage system performance under grid energy storage applications, Katie Zarich, a spokesperson for Cummins, told Utility Dive. University researchers will perform tests and develop an outdoor second-life demonstration system comprised of Cummins battery modules, according to a statement.

For Cummins, which founded its electrified power business in 2018, the partnership will provide valuable data on the aging behaviors of its battery modules.

“Electrification has the potential to play an enormous role as we move toward decarbonization of many industries, but in order to maximize that potential, it’s crucial that we focus on the sustainability of the entire product life cycle,” Julie Furber, vice president of electrified power of Cummins, said. “One piece of the puzzle that requires additional research is the second-life of batteries, and Cummins now has a highly-skilled and capable partner in UC San Diego as we move towards the development of reuse solutions.”

Used EV batteries maintain a significant battery capacity, up to 70%, according to Nissan and EDF. While this may no longer meet the requirements to power a vehicle’s drivetrain, it is sufficient capacity for less demanding applications, Cummins said.

The Indiana-based company also pointed out that repurposing batteries increases sustainability as it postpones recycling, which has proved to be a challenge.

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The cost of energy storage will be critical in determining how much renewable energy can contribute to the decarbonization of electricity. But how far must energy storage costs fall? In a study published August 7 in the journal Joule, MIT researchers answer this question. They quantify cost targets for storage technologies to enable solar and wind energy with storage to reach competitiveness with other on-demand energy sources. They also examine what kinds of batteries and other technologies might reach these targets.

“One of the core sources of uncertainty in the debate about how much renewable energy can contribute to the deep decarbonization of electricity is the question of how much energy storage can be improved” says senior author Jessika Trancik, an associate professor of energy studies at the Massachusetts Institute of Technology. “Different assumptions about the cost of energy storage underlie significant disagreements between a number of assessments, but little was known about what costs would actually be competitive and how these costs compare to the storage technologies currently being developed. So, we decided to address this issue head on.”

“Quantifying cost targets for energy storage required a new piece of insight,” Trancik says, ‘about how patterns of the renewable energy supply, and fluctuations in this supply, compare to electricity demand profiles. Large but infrequent solar and wind shortage events are critical in determining how much storage is needed for renewables to reliably meet demand, and it’s important to understand the characteristics of these events.”

In the paper, Trancik and her colleagues estimated the costs of using storage together with wind and solar energy to supply various output profiles reliably over twenty years. They then estimated cost targets for energy storage that would enable plants to reach cost-competitiveness with traditional electricity sources. They also evaluated current and future energy storage technologies against the estimated cost target.

The researchers’ model optimizes storage costs by using whatever combination of storage and solar and wind gives the lowest electricity cost. This often means oversizing solar and wind capacity relative to an intended output, to decrease the amount of storage needed.

The analysis also explored the characteristics that distinguish various storage options. Some technologies are more suited to inexpensively storing large quantities of energies but outputting it slowly, at lower power, while others can cost-effectively store smaller amounts that can be quickly discharged at high power. So the model needed to capture these differences, Trancik says.

The research found that technologies with energy storage capacity costs below $20/kWh could enable cost-competitive baseload power that is available all of the time over a twenty-year period, though this target varies with the target output profile and location. They found that electricity costs respond more to costs of storage energy capacity than power capacity.

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French oil giant Total (NYSE:TOT) may not be the first company you think of when renewable energy comes up, but it should be near the top of the list. The company owns a controlling stake in solar manufacturer SunPower (NASDAQ:SPWR) and battery company Saft, and its list of renewable assets seems to grow every day.

Saft is making some interesting moves, most recently partnering with some other power players in the energy business to research better battery technology. If successful, Total could emerge with a strong position in one of the biggest growth industries in energy.

French oil giant Total (NYSE:TOT) may not be the first company you think of when renewable energy comes up, but it should be near the top of the list. The company owns a controlling stake in solar manufacturer SunPower (NASDAQ:SPWR) and battery company Saft, and its list of renewable assets seems to grow every day.

Saft is making some interesting moves, most recently partnering with some other power players in the energy business to research better battery technology. If successful, Total could emerge with a strong position in one of the biggest growth industries in energy.

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