SAN DIEGO, July 22, 2019 (GLOBE NEWSWIRE) — Home solar storage offers low energy costs plus the security of backup power if/when the grid goes down. But when choosing a solar storage system, it’s important to consider the chemistry inside the battery. Most solar batteries on the market are lithium-based, and there are two main types: lithium ion and lithium iron phosphate. The names might sound similar, but in reality these batteries are quite different.

Lithium ion batteries contain cobalt, a toxic metal that comes with many serious risks. Cobalt is extremely harmful to both miners and the environment. On the consumer side, batteries with cobalt are prone to thermal runaway. When this happens, the battery rapidly overheats and can catch fire or explode. Combustion can also cause the release of toxic cobalt fumes.

Thermal runaway of lithium ion batteries has caused smartphones and electric cars to burst into flames. One well-known electric car maker that has had a string of highly publicized fire incidents uses the same lithium ion technology for its line of home solar batteries. Panasonic, whose automotive business partners with that company, has tried to cut down cobalt usage and is “aiming to achieve zero usage in the near future,” although it has yet to identify a replacement for cobalt.

The safer chemistry for home solar storage is lithium iron phosphate, which does not contain cobalt. These batteries are chemically and thermally stable and non-toxic. In head-to-head comparisons, they also last longer than their lithium ion counterparts.

San Diego–based NeoVolta Inc. designed its NV14 home energy storage system with safety in mind. The NV14’s lithium iron phosphate battery has superior thermal and chemical stability. It can withstand higher temperatures, while remaining cool and safe to touch. In the event of a power outage, the system will automatically disconnect from the grid via included auto transfer switch and will continue powering critical household loads indefinitely. The NeoVolta smartphone app allows users to monitor the system’s performance 24/7, and it’s backed by a ten-year warranty.

“When it comes to solar storage, there is an alternative to putting a toxic fire hazard in your home,” said Brent Willson, CEO of NeoVolta. “We’ve engineered our systems with cobalt-free lithium iron phosphate technology. Independent studies have shown that for safety, stability, and life cycle, lithium iron phosphate clearly outperforms lithium ion.”

About NeoVolta – NeoVolta designs, develops and manufactures utility-bill reducing residential energy storage batteries capable of powering your home even when the grid goes down. With a focus on safer Lithium-Iron Phosphate chemistry, the NV14 is equipped with a solar rechargeable 14.4 kWh battery, a 7,680-Watt inverter and a web-based energy management system with 24/7 monitoring. By storing energy instead of sending it back to the grid, consumers can protect themselves against blackouts, avoid expensive peak demand electricity rates charged by utility companies when solar panels aren’t producing, and get one step closer to grid independence.

Energy storage has always been a natural complement to solar energy systems, but the two never seem to find a successful way to work together in practice. Tesla’s (NASDAQ: TSLA) Powerwall was supposed to be a natural product to go with Tesla solar systems, but adoption has been weak because it’s still essentially an expensive toy.

Sunrun (NASDAQ: RUN) is one of the companies trying to change this dynamic and find ways for its Brightbox energy storage system to contribute to solar installations. Energy storage may not be the asset homeowners find the most value in, but it could still boost value after all.

Sunrun’s move in Oakland
Last week, the East Bay Community Energy (EBCE) board of directors agreed to replace a jet-fuel powered plant in Oakland, CA with home solar and energy storage systems from Sunrun in low-income housing in West Oakland and Alameda County. The project will string together thousands of energy storage systems in homes to form what’s known as a virtual power plant.

But it’s the financial mechanism behind those storage systems that make this such a big deal. Sunrun will build 500 kilowatts of power and 2 megawatt-hours of storage capacity, and offer capacity to the EBCE on a 10-year contract. What the utility is looking for is available capacity on days when the rest of the grid is stretched, like hot days when air conditioners are on high or days when there’s an outage in another part of the grid. Utilities usually pay for extra power plants to be available at those times — known as “capacity” — but energy storage might be able to take over this important role in the grid’s infrastructure.

How customers will see energy storage
The details aren’t all worked out, but the money Sunrun is making from the virtual power plant could offset some of the cost of a residential solar and storage system. Customers could be offered a discount up front or a reduced contract price over time if they participate in the capacity side of the energy storage deal.

The downside is that would give Sunrun more control over a homeowner’s energy storage system. If someone wants to use primarily energy they produce on-site, this would reduce its availability for that purpose. It may also reduce capacity available for backup power for homes.

However, that doesn’t mean there isn’t enough value for homeowners to still go forward with an installation. At the end of the day, few customers are intimately involved with how their solar or energy storage systems work, so they’ll be looking at the dollars and cents in savings being offered. Sunrun is hoping this capacity contract will help make solar and energy storage more economical for customers.

Over the past year and a half, the U.S. energy storage industry has been getting into arguments with grid operators over their plans to implement Federal Energy Regulatory Commission Order 841, the mandate to integrate energy storage assets into the country’s wholesale energy markets.

The biggest argument to date has been over PJM’s insistence on a 10-hour duration requirement for batteries to play in its capacity market.

Storage advocates and clean energy groups say the proposal violates FERC Order 841’s call for open and equal access for energy storage assets, by effectively making it impossible for lithium-ion batteries to economically compete against fossil-fuel-fired plants in the country’s biggest capacity market.

They’ve also complained that PJM hasn’t provided an analysis to justify such a long duration requirement, which is actually based on an old rule for pumped-storage hydro projects. But the groups challenging the data behind PJM’s proposed rule haven’t had their own analysis to counter it — until now.

Last week, the Energy Storage Association and Natural Resources Defense Council unveiled an analysis by Astrapé Consulting, using PJM data and industry-standard modeling, that indicates gigawatts’ worth of energy storage in 2-hour, 4-hour and 6-hour durations could provide the same capacity value as power plants that run 24 hours a day.

There’s a relatively simple explanation for this finding. While PJM may see its daily demand on peak days rise, peak and fall over the course of 10 hours or more, the true “peaks” at the very top of that demand curve “can presently be met by efficient dispatch of shorter-duration storage, given the current mix of supply resources,” ESA writes.

Specifically, “The results of our analysis demonstrate that with energy storage deployments up to 4,000 MW, 4 hours of duration allows those resources to provide full capacity value relative to a resource without duration limits,” Astrapé states.

The grid’s edge is taking a growing share of the revenue, and for good technical reason. California’s home mandate will accelerate this as solar power pricing plummets when integrated at time of construction. As our ability to manage our grid with home based solar+storage hardware increases, even larger grid benefits will come into view. And, even this morning, we’re seeing it happen in bigger ways.

National Grid has extended the application period for it ConnectedSolutions program in Rhode Island (pdf technical description) and Massachusetts (pdf technical description) to August 1. The program will pay home owners who install residential energy storage and give the electricity utility access to that hardware to make use of during high power grid demand moments.

In Rhode Island, National Grid arm (above image) will pay for summer and winter grid events, whereas in Massachusetts (below image) the utility will pay only during the summer. The program will limit any specific system to 75 individual events during the year, with the contract for this program lasting five years.

The Massachusetts program application is here (pdf) and the Rhode Island application here.

On SolarEdge’s Massachusetts ConnectedSolutions page, the company worked out the total revenue – per year – that could be gained if your system were to be used the maximum number of times the program.

A SolarEdge 7.6KW + Single LG Chem RESU-10H operating under ideal conditions, during all events in both summer and winter over the five-year performance period may earn up to $2,940 for summer events, and $650 for winter events, A possible total of $3590.

A SolarEdge 7.6KW + Two LG Chem RESU-10H performing optimally during all events in both summer and winter may earn up to $5625 for summer events and $1250 for winter events. A possible total of $6875.

Canadian company Hydrostor has just received approval to build the first grid-scale compressed air energy storage system in Australia.

Hydrostor will deploy a 5MW / 10MWh system at a former zinc mine near Strathalbyn, South Australia. The advanced compressed air energy storage (A-CAES) project, expected to cost AU$30 million (US$21.09 million) in total, received development approval and has been welcomed in statements by local politicians including South Australia’s energy and mining minister, Dan Van Holst Pellekaan.

“This is another step in the transition of South Australia’s energy system by the integration of renewable energy into the grid to deliver cheaper, more reliable and cleaner energy,” van Holst Pellekaan said.

“A-CAES is a new energy storage technology for Australia that provides synchronous inertia, load shifting and frequency regulation to support grid security and reliability.”

The system is designed to use surplus electricity generated by nearby solar and wind facilities to run compressors. Air is also heated as it is compressed and stored underground. A Hydrostor video explainer can be seen below.

Caverns will be dug 240 metres below the Angas Zinc Mine site, repurposing the existing mine to store the compressed air, which then drives a generator to produce electricity. The system will be used to help the local electricity network deal with times of peak demand, by outputting energy to the grid when needed.

It’s expected to have a 30-year lifetime in operation, with the South Australian government supporting the project directly with AU$3 million in funding through its Renewable Technology Fund. The national Australian Renewable Energy Agency (ARENA) is also contributing, putting in AU$6 million of the total cost.

London-based Highview Power has contracted with Nebraska-based Tenaska Power Services to help develop up to four gigawatt-hour scale cryogenic energy storage plants in the U.S. over two years, with the first project expected to be developed in the ERCOT market.

Highview’s technology uses electricity to chill and liquefy air at -320°F, stores the liquid air in insulated, low-pressure tanks, and later exposes the liquid air to ambient temperatures to rapidly re-gasify the air, expanding it to 700 times its liquid volume, to power turbines to generate electricity. The firm notes that its system can be configured to also use waste heat and cold.

Highview has been operating a 5-megawatt cryogenic energy storage facility in Manchester, England since June 2018.

Highview Power says the levelized cost is $140/MWh for a 200 MW/2 GWh (10-hour) system, with no use of waste heat or cold. The firm adds that its technology permits “weeks’ worth of storage,” with the use of additional tanks.

For comparison, Lazard has estimated that battery storage has a levelized cost of $108 to $140 per MWh for a utility-scale PV-plus-storage application. All cost estimates are sensitive to the assumptions used, particularly the capital cost, and the cost of capital.

Highview sees ERCOT as a promising market because it is “a big wind market—we can co-locate with wind resources to store power during off-peak hours,” said Javier Cavada, president and CEO of Highview Power, in a pv magazine interview.

The cryogenic energy storage technology can support “intermittent renewable generation, energy arbitrage, peak shaving, ancillary services, transmission and distribution deferral, inertia services, reactive power, and voltage support,” he said.

Highview’s pilot-scale facility in England uses waste heat from adjacent landfill gas engines, said Mr. Cavada, and the technology can also use waste cold—for example, from an LNG import terminal, where liquified natural gas is being re-gasified to put on a gas distribution network. He said that LNG process may use sea water to warm the LNG, thus chilling the sea water, and “the cold is simply being dumped.”

General Electric is a big and sprawling company that’s undergone some dramatic reorganizations over the past few years, particularly in its renewable energy, energy storage and grid edge business lines.

But over the past four years, amid these large-scale corporate changes, a small unit of GE has built a growing business around developing distributed solar and solar-plus-storage projects.

On Tuesday, GE announced it’s taking this business to a new stage, via a partnership and majority investment by asset management firm and heavyweight renewables investor BlackRock Real Assets.

The new company, named Distributed Solar Development, will be 20 percent owned by GE Renewable Energy and 80 percent owned by a fund managed by BlackRock. The business, which has been incubated within GE since 2012, will focus on commercial, industrial and public-sector customers.

Erik Schiemann, CEO of Distributed Solar Development and a veteran of various GE business units, said in an interview that the investment would allow the company to expand its current project development work — and, for the first time, own the projects it’s developing.

“What we specialize in at Distributed Solar Development is the origination, development, design, execution, building, and asset management of distributed solar and storage projects,” he said. Most of its projects to date have been behind-the-meter.

“BlackRock’s investment further advances our growth in that platform, allows us to take on new markets, and allows us to double down in the markets we’re currently successful in.”

And while the business hasn’t owned any of the projects it’s developed to date, that’s set to change with BlackRock’s investment. “The cash infusion allows us to participate as an owner of the assets,” he said.

BlackRock’s push into distributed energy resources
BlackRock Real Assets has primarily invested in utility-scale renewables, with $5 billion invested in over 250 wind and solar projects with a total generation capacity of over 5.2 gigawatts. But it has made moves into distributed-scale solar projects this year, including April’s undisclosed investment into small-scale solar project owner CleanCapital.

Batteries are now one of a “huge variety of distributed energy assets capable of providing flexible capacity to the network”, but failure to manage them correctly will limit the market opportunities available, as well as the lifetime of the systems themselves, the data science head of UK flexible energy tech company Open Energi has said.

In a blog published last week on our sister site Current± Open Energi’s Robyn Lucas explains how the “cost-benefit of every action performed by a battery energy storage system has to be weighed in terms of battery degradation and lifetime, whilst continuously managing the state of charge to ensure system availability.”

Both the throughput and cycling capabilities of batteries are essential metrics in modelling how they are to be used and what sort of revenues they can earn. As well as a more general look at the market dynamics and the technologies her own company uses to take on increasingly merchant-driven opportunities, Lucas’ blog takes a deep dive behind the workings of the grid-scale battery installed in North London at the stadium of professional football club Arsenal.

Thought to be the UK’s “first behind-the-meter battery to be aimed primarily at wholesale energy trading,” the fully-automated and optimised battery installation uses the battery to supply energy to the stadium facilities at the most expensive times of day.

“At the same time, the system is generating revenue – split between Arsenal, [developer] Pivot Power and investor, Downing LLP – from energy arbitrage and imbalance opportunities,” Lucas writes.

Read the full blog Throughput vs Revenues: Making the most of battery storage, at Current±, Solar Media’s energy transition news and analysis site.

When the PJM Interconnection* proposed that energy storage needed 10 hours duration to qualify for capacity payments, that seemed to make no sense.

No other grid operator had proposed such a requirement—essentially disqualifying battery storage—in its plan for complying with an order from the Federal Energy Regulatory Commission to allow energy storage to participate in all markets where it is technically capable of doing so (including capacity markets).

Now we have an analysis that debunks PJM’s proposal.

Storage with 4-hour duration can provide up to 4,000 MW of capacity of “equivalent reliability value” to that supplied by conventional power plants in PJM, according to a study by Astrapé Consulting.

Astrapé used the SERVM model for its analysis, a model it has used for similar evaluations it has performed for other regional grid systems such as ERCOT, MISO, and SPP.

Astrapé’s report concluded:

A 4-hour duration requirement would correctly represent the capacity value of storage under current market conditions and would remain accurate until the amount of installed storage in PJM increases by two orders of magnitude.”

The “two orders of magnitude” refers to the 40 MW of 4-hour non-hydro storage that Astrapé determined is currently operating in the PJM region, compared to the 4,000 MW potential.

The capacity payments at issue are intended to ensure that adequate reserve capacity is available to meet demand at occasional times of extreme demand, such as extremely hot or cold days.

But when storage is excluded from the capacity market, that causes the market-clearing price for capacity to be higher, increasing customers’ electric bills. Meanwhile, lower compensation for storage can limit otherwise cost-effective deployments of solar and wind power, which pair well with storage.

In its analysis, Astrapé followed an elegant approach illustrated in Figure 1. In step 1 as shown, Astrapé modeled the addition of conventional capacity to reduce the “loss of load expectation” (LOLE) to 0.1, a “generally accepted reliability criterion” that “represents a single day of firm load shed in a 10-year period.” In step 2, Astrapé modeled the addition of energy storage, reducing LOLE below 0.1. In step 3, Astrapé modeled the removal of conventional capacity until LOLE was again 0.1. This yielded a ratio of storage capacity added to conventional capacity removed.

Georgia Power is set to boost its state’s battery energy storage sector, with the company’s plan to own and operate 80MW of battery energy storage now approved by the Georgia Public Service Commission (PSC).

Georgia Power’s 2019 Integrated Resource Plan (IRP) has been approved by the Georgia Public Service Commission (PSC), in a unanimous decision. The plan includes energy storage, 72% more renewable generation by 2024, and approval of the company’s environmental compliance strategy.

Allen Reaves, Georgia Power’s senior vice president and senior production officer, said: “Working with the Georgia PSC, we are positioning Georgia as a leader in the Southeast in battery energy storage, which is critical to growing and maximizing the value of renewable energy for customers as we increase our renewable generation by 72% by 2024.

“Through the IRP process, Georgia Power will continue to invest in a diverse energy portfolio including the development of renewable resources in a way that benefits all customers to deliver clean, safe, reliable energy at rates that are well below the national average.”

Under the approved IRP, Georgia Power will both own and operate the 80MW of new battery energy storage, add 2,260MW of new renewable generation to the company’s energy mix and retire five coal-fired units across the state.

New energy efficiency programs for customers, including both an income-qualified program and aniIncome-qualified energy efficiency pilot program, were also approved in this plan.

Georgia Power filed requests with the PSC to both raise residential rates and seek approval for its IRP earlier this month, while elsewhere in the US, utilities in New Mexico and Tennessee have also filed major new plans that include significant mention of energy storage.