Dutch energy solutions company Alfen is supplying an integrated energy storage solution to enable electric vehicle charging for carmaker BMW.

The 1.1 MW system will be installed at BMW’s test location in Munich, Germany, and will incorporate an ultrafast charger for BMW Group’s EV prototypes.

The system is based on 34 BMW i3 car batteries and ensures maximum available power for the charging of EVs, irrespective of the capacity of the local power grid.

Alfen said: “One of the benefits of BMW i batteries is that these make the system transportable. This provides optimal flexibility to relocate the system to other locations in the future, wherever a backup for fast-charging of EVs might make sense. This addresses the increasingly imminent problem of concentrated fast charging of EVs in relation to the available grid capacity.”

Alfen has also signed an agreement with BMW to purchase the i3 car batteries for other storage projects.

Andreas Plenk, Global Sales Director for Energy Storage at Alfen, said: “We have been working with BMW i batteries at multiple storage projects, but are very proud to be selected to provide a storage system for one of BMW AG’s locations in Munich.

“As the energy transition evolves, we see more and more of our clients being interested in our integrated energy solutions capabilities, in which we combine our expertise in smart grids, EV charging and energy storage. We look forward to address the energy challenges of our clients.”

The UK government’s head of smart energy has admitted that Brexit – Britain’s planned departure from the European Union – is causing delays in the passage of primary legislation to define energy storage, which may not be achieved until 2022.

Speaking at yesterday’s Utility Week Live event in Birmingham, England, Will Broad was providing an update on the progress of the Smart Systems and Flexibility Plan (SSFP), which was published in July 2017, outlining 29 actions to enable the future energy system of the UK.

The plan set about to amend the Electricity Act 1989 and other relevant legislation to explicitly define electricity storage as a distinct subset of generation.

This was in opposition to many voices from industry that claimed energy storage should not be continually defined as a form of generation owing to its unique capabilities within the energy system.

Broad yesterday conceded that the vote to leave the European Union, and the associated legislative requirements, meant that time could not be secured within government to move forward on the issue.

“We’re still seeking opportunities for parliamentary time to define storage in primary legislation and Brexit is making this difficult. But we still commit to do it this Parliament,” he said.

The original Call For Evidence in November 2016, which resulted in the actions outlined in the SSFP, made clear the industry’s appetite for a bespoke definition of energy storage.

It was argued that the current generation class assigned to the technology has led to a series of barriers to deployment, such as double charging of final consumption levies at the time of both importing from and exporting electricity to the grid.

This has left developers clamouring for faster progress on the issue, with an audience member at yesterday’s event accusing Broad of using Brexit “as an excuse” for delays.

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The U.S. federal government is one of the nation’s largest energy consumers, and has been a primary customer of Ameresco since the company’s inception. They are natural partners, according to Bulgarino, because the federal government is a leader in incorporating and installing innovative technologies — the kind of products that differentiate Ameresco.

Ameresco has done billions of dollars of energy work with the U.S. government, mostly through performance contracting, through which the company guarantees energy performance and savings.

“The government doesn’t have to outlay capital, and that has been very key for them, obviously, through budget shortfalls over many years,” Bulgarino said.

Ameresco’a federal clients range from the General Service Administration (GSA) and Department of Defense to Army and Navy, and Marine bases, to the Veterans Administration, the U.S. Department of Agriculture and the Bureau of Prisons.

The federal sector pursues microgrids and distributed energy with a key objective — energy resiliency.

“Yes, there is definitely interest in resiliency, resiliency being their ability to maintain operations amid challenging events or unplanned events,” she said.

Concerns about cybersecurity drive government interest in energy resiliency, as does extreme weather, natural disasters, and the problem of aging infrastructure.

In fact, a recent Ameresco project  — a new energy system at the Marine Corp.’s Parris Island in South Carolina — arose out of these concerns. Parris Island is the Marine Corp.’s primary training base for new recruits.

Being on an island makes the base more vulnerable to utility failures from hurricanes and flooding.

Hybrid projects that are a combination of wind energy, solar PV, and other energy sources, are becoming a more and more attractive option to drive the energy transition to higher shares of renewable energy in the mix. Siemens Gamesa is one of the pioneers in this development with a long-term track record in hybridization and off-grid technology.

Now the company has taken another step and is testing a battery storage technology with large future potential.

At SGRE’s La Plana R&D site near Zaragoza, Spain, a redox-flow energy storage system has been commissioned. The system is connected to the hybrid controller of the combined wind and PV generation system and supplements the lithium-ion batteries that have been in use here for around two years.

The La Plana test-site integrates the next-generation Vanadium redox energy storage system with a wind turbine, solar-PV modules, and a diesel generator. The new redox flow battery offers a 120-kW energy output with a storage capacity of 400kWh. Siemens Gamesa has been refining its knowledge in hybridization over years.

A sophisticated flexible hybrid controller is the resulting product of this R&D effort. It is the digital core that coordinates the generation of all energy sources to meet the electrical load, in order to reduce the LCoE of the plant regardless of whether the grid is connected or disconnected. To reduce energy costs the controller is targeting to achieve the maximum integration of renewable energy.

Wind turbine maker Siemens Gamesa has installed a redox flow energy storage system for testing at its La Plana research and development (R&D) site near Zaragoza in Spain.

The vanadium redox flow battery has integrated the redox with a wind turbine, solar photovoltaic (PV) modules and a diesel generator at the test site.

Featuring 120kW energy output and storage capacity of 400kWh, the redox supplements lithium-ion batteries that have been in use at La Plana for about two years.

Siemens Gamesa said that all the technologies are connected to a flexible hybrid controller, which coordinates the generation of all energy sources to meet the electrical load and reduce the LCoE of the plant.

The firm said in a statement: “To reduce energy costs the controller is targeting to achieve the maximum integration of renewable energy.”

SGRE chief technology officer Antonio de la Torre said: “With the Redox-Flow technology commissioned at our La Plana test site, we are now active in all relevant storage technologies including Power-to-Heat and also battery storage systems.

“Due to its scalable energy capacity the Vanadium redox battery is a highly promising option to support our advanced technology offers for isolated and grid connected systems.”

Recently, Siemens Gamesa inaugurated a new technology and manufacturing centre in Madrid, Spain.

The new Gamesa Electric technology and manufacturing centre comprises two test benches for testing and validating systems with capacity of up to 10MW, for wind and solar photovoltaic (PV), as well as for energy storage purposes.

Siemens Games said it has invested more than €3m in the facility, which upgrades and expands an existing plant. The facility employs 183 people.

Employing 25,000 people, Siemens Games has installed products and technology in more than 90 countries. It has total capacity base of over 84GW.

Batteries could play a key role in helping to roll out an electric vehicle supercharger network across the U.K., according to a company called Pivot Power.

The firm, which describes itself as a special-purpose venture formed between energy storage project developer Become Energy and renewables investment company Downing, hopes to install the world’s biggest battery network.

It plans to deploy forty-five 50-megawatt batteries at substations close to major auto routes across the U.K. Each battery would make money from grid services and energy trading.

Crucially, though, the cost of adapting each substation for battery storage would also allow it to be used for EV charging.

By connecting rapid charging stations directly to the high-voltage transmission network, Pivot Power intends to gain access to up to 20 megawatts of cheap power per site. This would grant it efficiencies that would be hard to attain via regional distribution network connections.

The battery installations are a vital part of the plan, though, because converting a substation to deliver vehicle-charging services would require “seven figures’ worth of work to be done,” according to Matthew Boulton, chief operating officer.

“It’s not like a DNO [distribution network operator] application. It’s a far more complex process.”

This significantly weakens the business case for standalone vehicle charger installations. Under Pivot Power’s plan, though, “these chargers are only there because a 50-megawatt battery has paid for the connection,” Boulton said.

EV charging, once up and running, would create extra revenue for the battery system. The battery, meanwhile, would be able to store cheap electricity, so vehicle owners could charge their cars at a discount compared to standard tariffs.

Along with its 2-gigawatt battery network, Pivot Power aims to install the world’s largest network of rapid charging stations, with up to 100 rapid 150-kilowatt chargers plus 350-kilowatt charging points when the technology becomes available.

Shell has continued to scale-up its interest in distributed energy by participating in a €60 million (US$70.23 million) investment round by German battery storage firm sonnen.

Sonnen’s chief executive Christoph Ostermann told Reuters that Shell Ventures, the division of Royal Dutch Shell tasked with supporting innovative energy companies, would be among those participating in its latest investment round alongside existing shareholders.

And in a statement issued to Solar Media’s freshly launched clean energy site Current± this morning Brian Davis, vice president for energy solutions at Shell, confirmed the move.

“This investment enables us to combine Shell’s power business activities with sonnen’s high quality, innovative products and business model to enhance our consumer energy offerings. This is in line with our strategy to partner with leading companies to deliver more and cleaner energy solutions to our customers,” he said.

Ostermann also disclosed that the investment would enable sonnen to pursue expansion plans predominantly in the US and Australia, but also to ramp-up the development of its domestic aggregated storage platform sonnencommunity, its nascent virtual power plant solution and its grid-related services initiative. Back in 2016, Energy-Storage.News interviewed Ostermann as Sonnen netted US$85 million in a previous funding round when the CEO said expansion, internationalisation and development of innovative service and business models would be the focus for that cash.

The investment is however particularly interesting from Shell’s perspective given its recent moves into the domestic energy market.

In March this year Shell completed its acquisition of First Utility, one of the UK’s small- to medium-sized suppliers as part of a much wider consumer play.

When it first announced the deal in December 2017, Shell said its energy supply, trading and marketing expertise would enable First Utility to grow beyond its 825,000 customers and hoped to develop “more innovative” services for its customers.

The degree to which energy storage can compete economically with natural gas peaking plants is still being determined, but better price signals are needed to incentivize the most cost-effective reliability solutions regardless of technology, experts and analysts said Monday.

As lithium-ion battery prices come down and battery energy storage systems become more prevalent, some are beginning to question whether energy storage could be a cheaper, more efficient option for managing power grids than building natural gas-fired peaking power plants.

Gas-fired peaking plants can be started up quickly when power demand spikes, but they usually do not run very often.

The US has 120 GW of operating gas peaker capacity and 20 GW of peaker capacity planned by 2017, Ravi Manghani, director of energy storage at GTM Research, said in a presentation at the GTM Forum: Energy Storage vs. Gas in New York City.

The median capacity factor of the US’ 120 GW of gas peaking capacity was 3% and the median hours of run time per start was 5.3 in 2017, he said.

For example, the 199-MW Elk Station GT2 gas-peaking plant in Texas operated for 309 hours in 2017 and was started 47 times. The plant ran for an average of 6.6 hours when started and was only started one time during which it ran for more than 10 hours, Manghani said.

Manghani’s research indicates that on a $/MWh levalized cost of energy basis, eight-hour lithium-ion battery storage becomes competitive with peaking gas combustion turbines around 2022 and energy storage economics continuously improve to 2027, while gas peaker economics worsen. As a result, 32% of new US gas peaker capacity is at risk from four-hour storage by 2027.

Manghani’s team has only looked at costs so far and the next step would be to consider the revenues each asset could earn in different US power markets, he said.

Indeed, “the revenue side of the equation is unfolding now,” Rob Morgan, CEO of energy storage at GE, said. “Right now trying to parse out the value of storage is the challenge.”

It is still unclear whether energy storage can provide more value replacing gas peaker plants or being used for power transmission and distribution infrastructure deferral, Morgan said. The reality will probably vary based on policy and market rules in specific locations, according to conversations with multiple meeting participants.