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.

The use of electric car battery packs to create large energy storage projects is becoming increasingly popular.

Now, a new one made of BMW i3 battery packs is connecting to the UK National Grid and has become one of the largest to date.

The project is made of six shipping container sized units, five of which house 500 i3 BMW manufactured battery packs, which each have a 33 kWh capacity.

For a comparison, BMW delivered just over 500 i3 electric vehicles in the US last month. Therefore, it’s a significant portion of their battery pack manufacturing going to stationary energy storage.

The 22MW facility has been installed at Vattenfall’s Welsh onshore wind farm Pen y Cymoedd.

It shares the electrical infrastructure of the wind farm to create a hybrid renewable energy and storage asset.

Claus Wattendrup, Head of Business Unit Solar & Batteries, said:

This is Vattenfall’s largest battery installation to date, where we make use of synergies at our existing wind farms sites – such as at Pen y Cymoedd or the Princess Alexia Wind Farm in the Netherlands. Hybrid renewable parks will play a larger role in the future and we are leading this development.

It’s Vattenfall’s second large-scale energy storage project using BMW i3 battery packs.

After a 2.8 MWh energy storage facility built with batteries from over 100 BMW i3 electric cars in 2016, they used up to 1,000 BMW i3 battery packs for an energy storage project at another of their wind farms near Amsterdam.

We are seeing more automakers leveraging their electric car battery packs for energy storage systems.

For example, Renault is using old Zoe battery packs for a home energy storage product and energy storage systems to power off-the-grid charging stations.

Also, Nissan recently unveiled stunning new streetlights powered by used Leaf battery packs and solar.

BOULDER, Colo.–(BUSINESS WIRE)–May 22, 2018–A new report from Navigant Research analyzes the advantages of energy storage with fossil fuel (ESFF) solutions to maximize the efficiency, value, and useful life of fossil fuel power plants.

The development of energy storage has been tightly associated with the integration of renewable energy. However, energy storage is one of the most versatile technologies on the grid. Click to tweet: According to a new report from @NavigantRSRCH, a new generation of projects combining energy storage with fossil fuel (ESFF) generators is shifting the paradigm of how energy storage is utilized.

“At a time when market conditions are forcing power plants into premature retirement, energy storage can increase revenue and lower the costs to operate power plants,” says Alex Eller, senior research analyst with Navigant Research. “In the same way a hybrid car utilizes battery storage to improve efficiency and reduce fuel consumption, an energy storage system integrated with a conventional power plant can result in significant fuel savings while improving the grid’s overall resiliency.”

According to the report, market conditions and policies are driving acquisitions and new hybrid projects from incumbent generator providers. The pairing of storage with generators is also opening opportunities for new products and services both from companies serving large-scale utility markets and those focusing on distributed generation technologies for commercial and industrial customers.

The report ,, explores the advantages of ESFF solutions to maximize the efficiency, value, and useful life of fossil fuel power plants. The study examines the various strategies that market players are using to capitalize on this emerging trend and provides background on the development of ESFF solutions. It also details some of the key opportunities presented by the growth of ESFF solutions and projects and provides recommendations for utilities, vendors, and project developers. An Executive Summary of the report is available for free download on the Navigant Research website.

Think the plummeting costs of solar and wind are transforming the energy landscape? Then you should be betting on ways to warehouse that power.

To understand why, consider: Unlike almost all their rivals in the energy-generation space, solar panels and wind turbines are mass-produced goods. That means they’re subject to the rules of continual improvement and falling costs that we see with semiconductors, household products and clothing as production volumes rise and factories undercut each other. Traditional power plants are essentially large-scale construction projects, which rarely achieve the same sorts of efficiency dividends.

As a result, the cost of new-build renewables has been sinking. The highest-cost solar and wind projects in the U.S. will now produce electricity at least as cheaply as as the lowest-cost coal plants, according to a report last year by Lazard Inc.

In Australia, that price differential means one of the world’s largest coal exporters is unlikely ever to build another generator powered by the stuff, Catherine Tanna, managing director of EnergyAustralia Pty, told a Bloomberg Invest conference in Sydney Wednesday. By the early 2020s, renewables will have gotten so cheap that it will be more cost effective to build them than to operate even an existing coal or nuclear plant, Jim Robo, CEO of Florida-based NextEra Energy Inc., said during an investor call in January.

Negative Charge

The price premium for new solar generation over coal in Asia has slumped, and gone negative in India.

Coal miners hope to see a final leg of demand over the coming decade as incomes in emerging Asia rise — but even there, the rapidly falling cost of renewables means solid fuel is close to being priced out of the market, data from Bloomberg New Energy Finance show.

The trouble with things that get extremely cheap, however, is that you often end up with too much of them. That situation is exacerbated by the no-off-switch nature of wind and solar power. Take California’s recent mandate to put solar panels on the roofs of all new buildings. As my colleague Liam Denning wrote last week, one likely effect will be to push more electrons into a mid-afternoon electricity market that’s already glutted with supply.

A “may day”’ call this year came from the U.S. Department of Energy. The DOE made a $30 million funding commitment to long-term energy solutions through its Advanced Research Projects Agency-Energy (ARPA-E) office. “Long-term,” as defined in the project scope, starts at 10 hours and extends up to 100 hours of stored energy.

Funding from the new program called DAYS (Duration Addition to electricitY Storage) is open to any technology able to meet siting, output, and cycle requirements. And the solution must deliver an average cost of 5¢/kWh cycle across the range of storage durations.

Why Fund Energy Storage

The shift to renewable energy continues, despite uncertainty about the direction of U.S. policy under the current administration.

¤ Non-hydro renewable energy generation increased +15% in 2017 with wind and solar capacity reaching 143 GW, a 431% increase in the last decade.

¤ And a recent survey of North American utility companies from Utility Dive shows sector leaders remain bullish about the growth of renewable sources. Results shown in the table below indicate the industry recognizes the transformation cannot be implemented without energy storage:

The anticipated growth reflects current commitments to cleaner energy by leading U.S. utility companies.

¤ Consumers Energy in Michigan: 40% renewable energy by 2040.

¤ National Grid in the Northeast: 80% reduction in carbon emissions by 2050 (vs. 1990).

¤ Xcel Energy in the Central U.S.: 40% renewables by 2021, 60% by 2030.

¤ Ameren Missouri: Increase wind power to 700 mw by 2020 and solar to 50 mw by 2025.

¤ Duke Energy in the Southeast and Midwest: 40% reduction in carbon emissions by 2030.

¤ Southern California Edison: 80% solar, wind, hydro power by 2030.

¤ American Electric Power in the Southeast and Midwest: 80% reduction in carbon emissions by 2050 (vs. 2000).

¤ MidAmerican Energy in Iowa: 95% renewable energy by 2021.

¤ WEC Energy Group in Wisconsin: 40% reduction in carbon emissions by 2030

¤ DTE Energy in Michigan: At least 80% reduction in carbon emissions by 2050.

¤ First Energy in the Mid Atlantic: At least 90% reduction in carbon emissions by 2045 (vs. 2005).