A report out today on the causes of the UK’s recent blackout, where electricity supply to 5% of National Grid’s customers was cut off “to protect the other 95%”, highlighted that 475MW of batteries were used to help bring the network back online.

A timeline of events produced by National Grid ESO, based on interim findings conducted by the Electricity System Operator and submitted to regulator Ofgem on Friday evening, shows that a lightning strike the previous Friday evening had triggered events that led to loss of power for around 1.1 million customers and reportedly causing chaos on transport networks.

Our sister site Current± reported today that lightning hit a transmission circuit – the Eaton Socon – Wymondley Main. But while the grid’s protection systems operated normally and cleared the lightning within 0.1 seconds, shortly after there was a near simultaneous loss of load from both the Little Barford CCGT power station and Hornsea One offshore wind farm.

Those trips, National Grid ESO has concluded, were entirely independent of each other – dispelling a previous theory that a trip at one plant caused the other to de-load – but both were connected to the lightning strike. The lightning strike also caused some losses from embedded generators in the area of the lightning strike, equivalent to around 500MW, after the Loss of Mains protection system kicked in. All in all, close to 1.4GW of load was lost from the system, which is prepared for the loss of capacity equivalent to its biggest generator, a 1.2GW nuclear reactor, Sizewell B.

What National Grid described as an “extremely rare” event – the ESO deals with more than 1,000 lightning strikes a year – then occurred as frequency continued to fall even as 1,000MW of backup power was called on, including 475MW of battery energy storage.

Customers on the distribution network had to be automatically disconnected to “ensure the safety of the network in a controlled way and in line with parameters pre-set by the UK’s distribution network operators (DNOs), which feed power from the grid into peoples’ homes and businesses.

GlidePath Power Solutions has acquired eight wind projects in North Texas with a total capacity of 149MW.

The portfolio, purchased from Exelon Generation, will be optimised by GlidePath while it plans how best to add energy storage on-site at each project. The projects are all north of Amarillo and sell into the Southwest Power Pool (SPP).

Chris McKissack, Chief Operating Officer for GlidePath told Energy-Storage.News:

“We believe there’s an opportunity to build out storage facilities up to the nameplate capacity of the wind farms in the portfolio. There’s great potential for storage to reduce transmission congestion and improve the economics of wind farms in SPP and other markets.”

According to GlidePath, they will be the first battery storage projects in the SPP.

“The high penetration of wind energy in North Texas offers us an excellent opportunity to pair these facilities with the latest battery storage technology,” said David Braun, president, GlidePath Asset Management. “We look forward to managing these wind assets in a way that will hopefully strengthen the reliability of supply in the local electric grid and deliver benefits for Texas power consumers.”

In June, SPP revealed that it would launch the Western Energy Imbalance Service market (WEIS) with settlements every five minutes. The previous balancing market run by SPP was launched in 2007 and paid out US$103 million in its first year.

GlidePath has a 1GW battery storage development portfolio, including a 10MW /10MWh project in Texas announced in April this year.

It is often difficult to evaluate the benefits, effectiveness and costs of energy storage technologies. These benefits are dependent on how one uses storage and which technology is used for what purpose. The cost of using an energy storage asset also depends on the initial material and installation costs, as well as how well it is maintained during its service life.

These aspects are interconnected and, until now, customers have not been able to easily access this information with a simple test.

The new Levelized Cost of Using Storage (LCUS) method combines acquisition costs, operations and maintenance (O&M), expected use, and service life data into a single meaningful metric to compare different energy storage technologies.

When used properly, LCUS will allow users to make informed decisions when selecting the right energy storage technology for their specific application(s) more simply and effectively than any other method. LCUS is useful in three practical ways:

It compares the cost among different energy storage technology choices — whether they consist of different technologies, formats, designs or manufacturers.

It compares the costs of different applications of a particular energy storage technology or product.

It helps shed light on how certain operating modes affect the total cost of ownership.

True-to-Life Considerations
LCUS calculates the cost of the storage with respect to how much storage is really used, and not the size of the storage asset. It can compare the full cost of using different storage technologies and using the storage in different applications. It can also assess the trade-offs and limitations of different system designs, operating modes, application duties and service regimes.

North Carolina’s draft Clean Energy Plan was published last week, including the retirement of 4GW of coal and putting in place measures to drive renewable energy and EV adoption in the US state.

Governor Roy Cooper gave an executive order in October of last year which made a commitment to “address climate change and transition to a clean energy economy”. Cooper’s order, Executive Order 80, stated that by 2025 North Carolina “will strive to accomplish” three key aims: reduce greenhouse gas (GHG) emissions to 40% below 2005 levels, to increase the adoption of electric vehicles (specifically, zero-emission vehicles) to “at least 80,000” and to reduce energy consumption in state-owned buildings by at least 40% from 2002 – 2003 baseline figures.

As instructed by Executive Order No.80, the North Carolina Department of Environmental Quality’s State Energy Office has now published a draft plan which supports those aims, open to a brief period of public comment until 9 September. The policy and recommended actions document looks at short term, medium term and long term objectives and measures.

For short term implementation – i.e. within two months of the plan’s introduction, the office recommended the creation of a revised state Clean Energy Standard should include specific targets for 2030, as well as creating new incentives and targets, which could consider newer technologies such as energy storage which have not previously been included. Better mechanisms to reward energy efficiency need to be considered.

There is also the question of retiring and replacing fossil fuel plants, particularly coal and the document calls for retirement dates to be given for North Carolina’s coal plants that are shown be rapidly becoming uneconomical to operate. The same goes for “uneconomical peaking power plants”, with cooperatives and municipalities to be given more power to replace those peaking gas plants with low or zero emissions sources that can provide the same services.

Managing demand on the power grid continues to grow increasingly more complex. Along with the urgent need to reduce carbon-based energy generation, consumer demand for energy is growing and shifting hourly, daily, monthly, and seasonally. New distributed energy resources are being developed and integrated at a faster rate every day and renewable generation and its variability are being brought online faster than predicted. All these factors make it more challenging for all utilities to meet demand when and where it is needed.

As more aggressive goals are set to transition the electrical system away from fossil fuels, energy storage is poised to be the economical solution to address the rapid growth and variability of distributed renewable generation. Energy storage growth is market-driven as power can be worth less than zero at times in some regions and power providers look for ways to avoid investing in costly new generation assets. But this growth is also being incentivized and regulated by federal and an increasing number of state governments.

In early 2018, the Federal Energy Regulatory Commission (FERC) created Order 841 directing Regional Transmission Organizations and Independent System Operators to remove barriers to the participation of electric storage in wholesale markets. The U.S. Department of Energy announced a $30 million project to fund long duration research projects. And as of June 2019, 15 states led by California, Massachusetts, and New York have developed energy storage policies designed to meet aggressive carbon-reduction goals by encouraging further development and integration of new energy storage technologies.

Different energy storage technologies have different capabilities. Two metrics used by the U.S. Energy Information Administration to describe energy storage are power capacity and energy capacity. Power capacity is the maximum amount of power output available at any one instant and is measured in megawatts (MW). The energy capacity is the total amount of energy that a storage system can store or discharge and is measured in megawatt hours (MWh). Energy capacity is a factor of both the amount of power and the length of time that power can be discharged. A battery system that can discharge power for 4 hours or more is referred to as long duration energy storage. A Navigant Research report explains that, “Interest in long duration energy storage is rising as the rapid growth of variable output renewables continues and issues with grid stability and efficiency become more tangible for grid operators.”

August 19 (Renewables Now) – Japan’s NEC Corp (TYO:6701) today said its subsidiary NEC Energy Solutions (NEC ES) has secured contracts to install more than 20 MW of energy storage systems across New England.

The capacity will be added at municipal power plants at six sites in the states of Main and Massachusetts. One of those is a 3-MW/6-MWh facility for Massachusetts utility Taunton Municipal Lighting Plant, which will be among the largest in New England once completed.

The energy storage systems will use NEC’s GSS end-to-end grid storage solution and AEROS software control platform. The goal will be to lower the municipal power plants’ electric loads during peak periods and in turn trim capacity and power transmission costs, NEC explained.

Some of the projects, such as those in Wakefield, Ashburnham and Taunton, were realised with grants from the Advancing Commonwealth Energy Storage (ACES) programme. ACES represents a partnership between the Massachusetts Clean Energy Center (MassCEC) and the state Department of Energy Resources (DOER) that aims to support innovative “broadly-replicable” energy storage projects in Massachusetts.

Steve Fludder, CEO of NEC Energy Solutions, noted that the company has installed more than 750 MW of energy storage systems globally.

Most of the energy storage coverage by CleanTechnica is about utility-scale, residential, or business solutions and this is all reasonable and beneficial. At the same time, energy storage can also be used during natural disasters to provide back-up electricity for various applications and organizations. In this particular case, the application is an essential one: telecommunications. Caban Systems CEO, Alexandra Rasch, answered some questions for CleanTechnica about the grant.

Why did Caban Systems receive the California Energy Commission (CEC) grant, and what was the application process?

Caban Systems received this grant in response to telecommunications disruptions during the 2017 and 2018 wildfires. The California Energy Commission is committed to applying innovative energy technology services that will prevent any disruption to telecommunications service during the event of a natural disaster or during public safety power shutoffs (PSPS).

The CEC issued a solicitation, GFO-18-302 “Prototype to Production: Modular Battery Platform Project for CA Critical Infrastructure. Caban Systems’ mission aligned perfectly with the grant description to scale production and promote clean jobs in the state.

What will the money be spent on?

This capital will be used to expand production of energy systems at the Caban System’s headquarters in Burlingame, California, to meet growing customer demand in California.

Many of our readers are familiar with energy storage hardware like battery systems, but what is software-enabled energy storage and why is it important?

A software-enable energy storage system is enabled by an algorithm-based approach to monitoring and managing a telecommunications provider entire system through their web platform. Our real-time dashboard breaks down the energy source and loads, allowing managers to take action before a breakdown in communication ever occurs. This is important because it allows multiple operators to manage each individual load through bi-directional communication, anticipate a disruption in service and prevent a disruption before it takes place.

Caban provides grid-independent solutions that support telecommunications, but what benefits do they provide to everyday phone users and businesses?

The most significant benefit that Caban offers to everyday phone users and businesses is reliability for the strength and dependability of the telecommunications to customers that live in vulnerable areas.

For customers, Caban partners with solar and wind manufacturers to offer integrated solutions, enabling customers further access to renewables, which often times empowers customers to meet emissions reduction goals.

The board of education at a California school district which found that it could use batteries to reduce energy bills at seven learning facilities by US$5.7 million has contracted ENGIE Storage to deliver 3.5MW / 7MWh of energy storage systems.

ENGIE Storage announced the lithium-ion battery projects for Downey Unified School District in Downey, Los Angeles – which will split the battery capacity across separate systems coordinated by the company’s GridSynergy software – last week.

Downey Unified School District Superintendent Dr John Garcia said the schools’ board is “always looking for creative ways to save money and energy storage will provide our district with utility cost savings” and said that energy storage would, starting with this year, reduce energy bills significantly “for years to come”.

The district was able to fund the projects through California’s Proposition 39 legislation, which assists with energy efficiency and clean energy generation and use by schools. It will save US$5.7 million for Downey Unified over the next decade or so that the batteries will be in use, by reducing the amount of energy drawn from the grid at times when the air conditioning is running or stadium lights are in use, for example.

The peak energy used by schools is billed for by the state’s Investor-Owned Utilities in the same way that it is for commercial entities – so-called Demand Charges are levied each month based on those peaks, seen from the utility side of the meter as spikes in grid usage. Demand Charges can constitute as much as 50% of energy bills and although energy storage cannot mitigate them entirely, these charges in California have, on average, grown 80% in the past 10 years and the savings are still considered significant.

In addition to saving the district millions of dollars, the energy storage projects will “help enhance the reliability of California’s electric grid by reducing the strain on overloaded utility distribution networks,” ENGIE Storage CEO Christopher Tilley said. The company, known as Green Charge prior to takeover by ENGIE, has already executed projects at 80 schools.

As far back as 2017, solar industry veteran Jigar Shah told Energy-Storage.news that energy storage was even then a compelling proposition for school districts in North America, as his company Generate Capital delivered Sharp SmartStorage units coupled with solar for Santa Rita Union School District (SRUSD), also in California.

At that time, Shah said that although the energy bill savings were one component of the value proposition, energy resiliency and in that particular case, the option to use the storage systems as backup power had really got the project over the line with decision makers.

Energy Toolbase hosted a webinar recently entitled “Modeling the Economics Residential Energy Storage Projects in California” where we shared our latest insights on the market. We’re constantly learning and adjusting our thinking as the market evolves. We’re fortunate to have a front row seat, working closely with many of the leading energy storage system (ESS) equipment vendors and project developers in California.

From that webinar and our experience in the industry, here are the top 6 big-picture thoughts on the current state of the residential storage market in California from Energy Toolbase:

Demand is strong and projected to continue growing rapidly
Market data definitively shows that residential storage deployments in California are growing rapidly. The Smart Electric Power Alliance recently published the “2019 Energy Storage Market Snapshot” report, which reported 175.5 MWh of residential storage capacity added in 2018, which was an increase of 500% compared to 2017 levels. In California alone, the report counted 99.9 MWh of residential storage interconnected in 2018, an increase of 629% vs. 2017 levels.

Wood Mackenzie’s “Q2 2019 U.S. Energy Storage Monitor” report also ranked California as the top state for residential storage deployments for 2018 and also Q1 of 2019. The report forecasts strong continued growth in the residential segment over the next five years, with annual megawatt storage deployments expected to more than double in 2020 vs. 2019. Looking out over the next five years, WoodMac forecasts residential deployments to grow by over five-times in 2024 vss 2019 projections.

The current allotment of residential Self-Generation Incentive Program (SGIP) dollars is virtually gone. SDG&E exhausted its residential budget over a year ago, PG&E recently opened step 5 of 5 in early July and reserved all funds in less than three weeks. SCE is currently in step 5 of 5. Meanwhile, on the commercial side, SDG&E, PG&E and SCE are still in step 2 or 3 of 5 for SGIP. The good news for residential storage developers is that the SGIP budget is scheduled to get a huge replenishment soon thanks to Senate Bill 700 which passed the California legislature last year.

California has the best TOU rates for residential ESS economics in the country
We’ve evaluated residential time-of-use (TOU) rates in every state and California’s are the most advantageous for energy storage economics in the country. This is especially relevant given that all new solar customers in the big three investor owned utility (IOU) territories in California are now required to take service on a TOU rate after going solar, which was mandated in the big NEM 2.0 ruling in 2016.