The past month has been littered with news of exceptionally large battery storage developments, yet none in the world can compare to the news that Vistra’s permit to expand an energy storage system under construction at its natural gas-fired Moss Landing generation station to 1,500 MW/6,000 MWh has been approved.

That’s right. Gigawatt-scale battery energy storage is on the table.

The proposed expansion would quadruple the battery system’s size and make it the largest battery storage installation in the world, a couple of times over.

While the permit has been approved, the expansion will happen “should market and economic conditions support it,” according to Vistra President and CEO Curtis Morgan.

For some perspective as to how large this battery is, consider that, according to the U.S. Energy Information Administration, the country’s entire installed battery storage capacity at the end of 2018 came in at 869 MW, while total installed battery storage at the end of 2019 (including behind-the-meter) was approximately 1.7 GW, according to Wood Mackenzie. This one battery, when completed, will be larger in capacity than every other utility-scale battery energy storage system in the country, combined.

The system is coming in stages, only two of which have been formally announced. The first 300-MW phase is planned for completion by the end of 2020, with the second, a 100-MW expansion expected to come a year later in 2021.

Global perspective

This system is not the only gargantuan battery going in at the Moss Landing site. Set to clock in at 182.5 MW and 730 MWh, the Moss Landing battery energy storage system will be comprised of 256 Tesla Megapack battery units on 33 concrete slabs at the substation. The project’s targeted completion and energization is set for early-2021, with the project achieving full commercial operation in Q2 2021.

The more variable renewable energy there is in the grid, the higher the value of utility-scale storage systems. Researchers from the Massachusetts Institute of Technology (MIT) have used a high temporal resolution capacity expansion model called GenX to determine the least-cost approach to deploying large-scale storage into a low-carbon power system.

Lead-author and research scientist at the MIT Energy Initiative, Dharik Mallapragada, and his colleagues published their results in the journal article, Long-run system value of battery energy storage in future grids with increasing wind and solar generation, which appeared in the academic periodical Applied Energy.

In this research, the team attempted to identify the various sources of value generation that a storage system can tap into and the respective economic dynamics connected to these value sources. The most significant source of value for battery storage assets is the subsequent capacity deferral. Where a grid operator installs battery storage capacity, expensive transmission line capacity or natural gas plants can be avoided.

“Battery storage helps make better use of electricity system assets, including wind and solar farms, natural gas power plants and transmission lines, and that can defer or eliminate unnecessary investment in these capital-intensive assets,” says Mallapragada. “Our paper demonstrates that this capacity deferral, or substitution of batteries for generation or transmission capacity, is the primary source of storage value.”

To come to this conclusion, the researchers analyzed the holistic system value of energy storage. Specifically, the team looked at two variants of abstract power systems in the U.S.’ Northeast and Texas regions. To this end, information on load profiles and generation data for variable renewable energy was consistent with real-world figures.

We are in the middle of the most remarkable transformation in the history of the electricity grid — from dirty and centralized to clean, distributed, and digital. Many policymakers and pundits believe that if only we had enough batteries, we could adapt to this new mix of generation resources and continue to pretend that nothing but a few operating conventions have changed.

And indeed, utilities, regulators and state legislators are allocating ever-larger piles of ratepayer and taxpayer money to subsidize lithium-ion batteries on both sides of the meter. Subsidizing batteries sounds simple and wonderful, but the unspoken problem is that the emperor has no clothes. There is no economic model of behind-the-meter batteries for grid purposes — period.

Don’t get me wrong: I love batteries. I drive a battery to work every day. I’ve checked the math behind utility-scale batteries combined with renewables as a substitute for gas peakers, and in many places, it checks out. I even understand the attraction of batteries in microgrid or resilience projects, as a clean but expensive alternative to generators.

But as an energy economist and former utility rate designer, I am cursed with the ability to do basic arithmetic, so to be clear: The economics of behind-the-meter (BTM) batteries in grid-connected commercial buildings are and will continue to be wasteful, inefficient and impractical, to put it kindly.

I know, I know. You’re saying, “But lithium-ion batteries are really cheap, and they keep getting cheaper, and that changes everything!”

Except that it doesn’t. I read the same reports as you do, but those $150-headed-toward-$100/kWh numbers for battery capacity prices have nothing to do with the installed cost of a battery in a commercial facility. We are not making master electricians any cheaper, nor permitting any easier, nor fire suppression any less necessary, nor commercial floor space any more widely available.

In our experience with real-world small to medium commercial solar buildings, the actual all-in installed cost of BTM batteries is about $1,000/kWh — or more. That means that even if the price of lithium-ion batteries at the factory gate reaches $0/kWh (not a typo), the installed price will still exceed $850/kWh. That is cost-prohibitive in grid-connected commercial buildings everywhere.

Tesla TSLA +5.2% and PG&E recently broke ground on a record-setting energy storage system in Moss Landing (Monterey) California that, once complete, will be the largest such installation in the world. The battery park will be able to dispatch up to 730 megawatt hours (MWh) of energy to the electrical grid at a maximum rate of 182.5 MW for up to four hours using 256 of Tesla’s lithium-ion (Li-ion) Megapacks. Tesla and PG&E will have the option to upgrade Moss Landing’s capacity to bring the system up to 1.2-gigawatt-hours which could, according to Tesla, power every home in San Francisco for six hours.

The facility is expected to come online in 2021 and will be designed, constructed, and maintained by both companies, with PG&E retaining ownership. The construction of the Moss Landing site and other such mega-storage projects around the world portends a massive shift away from hydrocarbon-based power systems towards renewable generation backed up by utility-scale storage. According to Fong Wan, a senior vice president at PG&E:

“Battery energy storage plays an integral role in enhancing overall electric grid efficiency and reliability, integrating renewable resources while reducing reliance on fossil fuel generation. It can serve as an alternative to more expensive, traditional wires solutions, resulting in lower overall costs for our customers…the scale, purpose and flexibility of the Moss Landing Megapack system make it a landmark in the development and deployment of utility-scale batteries”

If the Moss Landin site is upgraded to the 1.2 GW capacity as anticipated, its storage capacity will be approximately ten times larger than Australia’s Hornsdale Power station, the previous record holder and another Tesla project. The next largest Li-ion storage system in the world is the United Kingdom’s Stocking Pelham station at 50 MW.

The construction of the battery farm in Moss Landing promises improved flexibility for grid demand spikes and load smoothing for variable generation from renewables. PG&E predicts that the Tesla Megapack system will save consumers more than $100 million over the project’s 20-year life span when compared to the forecasted local capacity requirements and procurement costs necessary in absence of the facility.

China is the world’s largest greenhouse gas emitter, and is building the most power plants of any country in the world, making its decarbonization paramount to preventing dangerous climate change. But the costs of wind, solar, and energy storage have fallen so fast that building clean power is now cheaper than building fossil fuels – a lot cheaper.

New research shows plummeting clean energy prices mean China could reliably run its grids on at least 62% non-fossil electricity generation by 2030, while cutting costs 11% compared to a business-as-usual approach. Once again, it’s cheaper to save the climate than destroy it.

While fast-falling clean energy prices make China’s clean energy transition possible, only smart policy can achieve a low-carbon electricity future. Fortunately, this clean energy transition would also spur long-term sustainable economic growth while cleaning the country’s air.

Short-term decisions, long-term impact

COVID-19 sparked a global emissions drop—China’s tumbled by an estimated 25% in the first quarter of 2020. But without decisive action to transform the country’s energy system, the pandemic could be a blip in China’s long-term rising emissions trend. May data showed a rapid rebound driven by coal power and cement production, with emissions up 4% to 5% year over year.

The economic recovery choices China makes today could either improve or worsen its air and water quality. While the Ministry of Ecology and Environment recently affirmed the country’s climate commitment, which promises to peak emissions and reach 20% non-fossil electricity generation by 2030, its coronavirus recovery effort could lean heavily on polluting sources as China approved more coal permits in March 2020 than all of last year.

In the transition to a decarbonized electric power system, variable renewable energy (VRE) resources such as wind and solar photovoltaics play a vital role due to their availability, scalability, and affordability. However, the degree to which VRE resources can be successfully deployed to decarbonize the electric power system hinges on the future availability and cost of energy storage technologies.

In a paper recently published in Applied Energy, researchers from MIT and Princeton University examine battery storage to determine the key drivers that impact its economic value, how that value might change with increasing deployment over time, and the implications for the long-term cost-effectiveness of storage.

“Battery storage helps make better use of electricity system assets, including wind and solar farms, natural gas power plants, and transmission lines, and that can defer or eliminate unnecessary investment in these capital-intensive assets,” says Dharik Mallapragada, the paper’s lead author. “Our paper demonstrates that this ‘capacity deferral,’ or substitution of batteries for generation or transmission capacity, is the primary source of storage value.”

Other sources of storage value include providing operating reserves to electricity system operators, avoiding fuel cost and wear and tear incurred by cycling on and off gas-fired power plants, and shifting energy from low price periods to high value periods — but the paper showed that these sources are secondary in importance to value from avoiding capacity investments.

For their study, the researchers — Mallapragada, a research scientist at the MIT Energy Initiative; Nestor Sepulveda SM’16, PhD ’20, a postdoc at MIT who was a MITEI researcher and nuclear science and engineering student at the time of the study; and fellow former MITEI researcher Jesse Jenkins SM ’14, PhD ’18, an assistant professor of mechanical and aerospace engineering and the Andlinger Center for Energy and the Environment at Princeton University — use a capacity expansion model called GenX to find the least expensive ways of integrating battery storage in a hypothetical low-carbon power system. They studied the role for storage for two variants of the power system, populated with load and VRE availability profiles consistent with the U.S. Northeast (North) and Texas (South) regions. The paper found that in both regions, the value of battery energy storage generally declines with increasing storage penetration.

A new report from the Energy Information Administration (EIA) details a sharp increase in utility-scale battery storage systems in the United States.

In 2010, there were seven operational battery storage systems in the country, which accounted for 59 megawatts (MW) of power capacity and 21 megawatt hours (MWh) of energy capacity, or the total amount of energy that can be stored or discharged by a battery. By the end of 2018, there were 125 operational battery storage systems in the United States, providing a total of 869 MW of installed power capacity and 1,236 MWh of energy capacity.

Battery storage systems store electricity and redistribute it later as needed. Historically, most utility-scale battery storage capacity is installed in regions covered by independent system operators (ISOs) or regional transmission organizations (RTOs). PJM Interconnection (PJM), which manages the power grid in 13 eastern and Midwestern states as well as the District of Columbia, and the California Independent System Operator (CAISO), accounted for 55 percent of the total battery storage power capacity built between 2010 and 2018. However, in 2018, more than 58 percent (130 MW) of new storage power capacity additions were installed in states outside of those areas.

In 2018, Alaska and Hawaii, the Electric Reliability Council of Texas (ERCOT), and the Midcontinent Independent System Operator (MISO) all added greater amounts of battery storage capacity to their power grids. Alaska and Hawaii, which have isolated power grids, are expanding battery storage capacity to increase grid reliability and reduce dependence on fossil fuels.

Also, the average costs per unit of energy capacity decreased 61 percent to $834 per kWh between 2015 and 2017. The large decrease in cost makes battery storage more economical, which helps accelerate capacity growth.

Q CELLS will acquire US energy storage software company Geli, as the solar company targets becoming a complete provider of “smart energy solutions”.

The planned acquisition also marks Q CELLS’s first entry into the US commercial and industrial (C&I) distributed energy market. The PV module manufacturer-turned integrated solar solutions provider has signed an agreement to acquire 100% of Growing Energy Labs Inc (Geli), and the transaction remains subject to regulatory approvals.

Geli was one of the early US energy storage market players to focus primarily on software offerings. The San Francisco company’s software platform is used for designing, automating and managing battery storage systems, and is intended to streamline the development process for energy storage. All the way back in 2016, Energy-Storage.news picked out Geli as one of 20 promising disruptors in the advanced energy storage industry.

“There is increasing demand in the energy storage space for comprehensive energy solutions. We are excited to welcome the Geli team and work together to strengthen our competitiveness in the global distributed energy market,” Q CELLS CEO Hee Cheul ‘Charles’ Kim said.

Kim added that the two companies’ combined capabilities would allow them to provide smart energy solutions to customers. Q CELLS provides solar cells and modules – as well as energy storage including systems made by supply partner Eguana Technologies – and also has a downstream project business and energy retail arm.

The company launched a 100% renewable energy offering to customers in Germany earlier this year; households with batteries and solar PV can subscribe to a service where their excess demand is covered by renewable energy generated by other households via the Q CELLS cloud.

Red brick is a universal building material produced by thousand-year-old technology that has seldom served any other purpose throughout history. Typically used for construction and architectural esthetics, red bricks are one of the most durable materials.

The bricks comprised of fused particles of silica (SiO2), alumina (Al2O3) and hematite (α-Fe2O3). The red color of a brick originates from hematite. State-of-the-art energy storage materials are also produced from hematite.

Considering this fact, a new study by the Washington University in St. Louis suggested that red bricks can be converted into energy storage units that can be charged to hold electricity, like a battery.

Chemists in Arts & Sciences have developed a method to make or modify “smart bricks” that can store energy until required for powering devices. In their study, scientists have shown that a brick directly powering a green LED light.

Julio D’Arcy, assistant professor of chemistry, said, “Our method works with regular brick or recycled bricks, and we can make our bricks as well. The work that we have published in Nature Communications stems from bricks that we bought at Home Depot right here in Brentwood (Missouri); each brick was 65 cents.”

D’Arcy and colleagues, including Washington University graduate student Hongmin Wang, first author of the new study, showed how to convert red bricks into a type of energy storage device called a supercapacitor.