Known historically for its oil and in the present day for deploying large amounts of wind energy and latterly for deploying batteries at wind farms, the US state of Texas is less well known for solar-plus-storage projects.

UK-headquartered multinational developer and EPC (engineering, procurement and construction) provider RES Group has just announced however that it has been contracted by Texas utility CPS Energy to execute a 5MW(AC) solar project co-located with 10MW / 10MWh of lithium-ion battery energy storage.

The combined system will be capable of capturing peak solar production around the middle of the day, to be stored and injected into the grid in the late afternoon and evenings when consumer demand has its own peak and solar production has tailed off for the day.

While the overall system size is relatively small, RES (Renewable Energy Systems) said that the distributed solar capacity is paired with a battery system that will be “strategically sized and configured” to optimise its effectiveness. RES also said that this solution could be scalable for use in other projects, touting the fact that it will help meet peak demand with lower emissions and more flexibility than existing and available balancing from fossil fuel generators.

The project will be located at what appears to be a former industrial plot of land in San Antonio now belonging to Southwest Research Institute (SwRI), with RES having been selected through a competitive process. The company will perform EPC tasks and carry out maintenance with construction scheduled to begin in October for the start of commercial operation by May 2019. SwRI will use its hosting of the project as an opportunity to “showcase” it.

“As beneficial as the site will be to the city’s energy future, SwRI will also benefit by leveraging the facility to become even more active in the grid-scale energy storage industry, and to work with battery suppliers and component manufacturers,” SwRI powertrain engineering division VP Daniel Stewart said.

Our clean energy future will require more energy storage to help ensure the lights stay on when the sun isn’t shining or the wind isn’t blowing. Your shiny new electric vehicle may also become an important type of battery for our power grid.

New research shows that leveraging the storage potential in electric vehicles, instead of just investing in stand-alone stationary batteries, could save utility customers billions of dollars, while also encouraging drivers to ditch gasoline. A study recently published by researchers at the Lawrence Berkeley National Laboratory (LBNL) shows that the electric vehicles (EVs) expected in California in 2025 could be used to meet the majority of the Golden State’s energy storage mandate that calls for 1.3 gigawatts (GW) of battery capacity by 2024. In fact, EVs can accomplish this both reliably and at about one-tenth the cost of stationary energy storage approaches. This level of storage could power nearly one million average homes, at least for a short while.

That EVs can be this valuable to the grid is a hugely significant finding.

One third of California’s electricity already comes from renewable resources like wind and solar, and the state is on track to meet its goal of generating at least half of its electricity from renewable resources by 2030. And if California Senate Bill 100becomes law this year, the goal for 2045 would be for 100 percent of California’s electricity to come from renewable or zero-carbon sources.

That’s great news for cleaning up our electricity supply, but increasing our reliance on variable resources like wind and solar generation necessitates overcoming a different set of challenges to manage the electrical grid. Thankfully, we already have proven ways to address these potential issues, including better weather forecasting, sharing power across broader geographical areas, and, most pertinent to this blog, the prudent use of stand-alone batteries and EV batteries.

The challenge of integrating variable resources like wind and solar can be depicted by the lovingly-termed “duck curve.” At its core, the “duck curve” depicts the large swing in net electricity demand and supply that occurs through the day as the sun moves across the sky or wind patterns change, and electricity supply is needed from non-renewable resources. This has implications for how grid operators must manage the various resources to ensure reliability. The graph below takes a typical spring day (March 31) and plots out what the “net load” would be from 2012 to 2020. Renewable electricity is assumed to satisfy the power demand first, and the leftover, unserved demand is termed “net load.”

A week ago, we wrote about two bills which are pending in the California legislature that could re-shape the state’s grid. It turns out that we missed one.

We had given up on SB 700, the bill that would extend the state’s popular Self Generation Incentive Program (SGIP) for another five years, after it languished for weeks in the Appropriations Committee of the California Assembly this summer. But as it turns out, the bill was not yet dead.

Following a rally by an estimated 200 solar workers on August 14, SB 700 was passed 12-5 out of the Assembly Appropriations Committee on August 16, and is now expected to go to the floor of the Assembly, its final stop before the desk of Governor Jerry Brown (D).

California Solar and Storage Association (CALSSA), which sponsored the bill and promoted the Tuesday rally, says that SB 700 is of “critical” importance in meeting the state’s clean energy goals as well as protecting tens of thousands of jobs in the residential solar industry.

“SB 700 will do for storage what SB 1 did for solar over a decade ago, namely create a mainstream market by driving up demand and driving down costs all while creating jobs and clean energy choices for consumer,” stated CALSSA Executive Director Bernadette Del Chiaro in a press statement.

While energy storage is being promoted in California through a variety of policies including mandatory procurement by utilities under AB 2514, many of these policies lean towards supporting large-scale storage. By contrast, SGIP has been a key subsidy for behind-the-meter installations, but will run out in 2020.

Current law authorizes state regulators to collect up to $166 million per year from the state’s big three investor owned utilities through the end of 2019 for this program, and under SB 700 this would be continued through the end of 2024, meaning up to $700 million in additional storage incentives to continue the program through the end of 2025.

Storage as a solution to TOU rates

In a press statement for the Tuesday rally, CALSSA specifically mentions the shift to time of use rates for residential solar as a threat to California’s solar workers. These rates have continually been pushed to later in the day by utilities, disadvantaging residential solar.

Thanks to the modern electric grid, you have access to electricity whenever you want. But the grid only works when electricity is generated in the same amounts as it is consumed. That said, it’s impossible to get the balance right all the time. So operators make grids more flexible by adding ways to store excess electricity for when production drops or consumption rises.

About 96% of the world’s energy-storage capacity comes in the form of one technology: pumped hydro. Whenever generation exceeds demand, the excess electricity is used to pump water up a dam. When demand exceeds generation, that water is allowed to fall—thanks to gravity—and the potential energy turns turbines to produce electricity.

But pumped-hydro storage requires particular geographies, with access to water and to reservoirs at different altitudes. It’s the reason that about three-quarters of all pumped hydro storage has been built in only 10 countries. The trouble is the world needs to add a lot more energy storage, if we are to continue to add the intermittent solar and wind power necessary to cut our dependence on fossil fuels.

A startup called Energy Vault thinks it has a viable alternative to pumped-hydro: Instead of using water and dams, the startup uses concrete blocks and cranes. It has been operating in stealth mode until today (Aug. 18), when its existence will be announced at Kent Presents, an ideas festival in Connecticut.

On a hot July morning, I traveled to Biasca, Switzerland, about two hours north of Milan, Italy, where Energy Vault has built a demonstration plant, about a tenth the size of a full-scale operation. The whole thing—from idea to a functional unit—took about nine months and less than $2 million to accomplish. If this sort of low-tech, low-cost innovation could help solve even just a few parts of the huge energy-storage problem, maybe the energy transition the world needs won’t be so hard after all.

Independent energy storage solutions developer Convergent Energy + Power (Convergent) has commissioned North America’s biggest behind-the-meter energy storage system in Sarnia, Ontario.

The system, with a storage capacity of 10MW/20 MWh, will help Convergent reduce Global Adjustment charge for an industrial customer.

Global Adjustment, which accounts for nearly 70% of the average industrial electricity bill in Ontario, encourages large electricity users in the region to minimise their power consumption during the most expensive grid periods.

Convergent CEO Johannes Rittershausen said: “This system combines cutting-edge technology and design with Convergent’s unparalleled peak dispatch services, creating maximum savings for our customer.

“Commissioning the biggest behind-the-meter energy storage system in North America would not have been possible without a forward-thinking customer and the innovation of our supplier, IHI.”
Apart from delivering the energy storage system, Convergent has also contracted IHI Energy Storage to provide operations and maintenance services and a capacity guarantee for the system.

The system, which is capable of powering an electric bullet train for 500 miles, has already reached this summer’s peaks causing no interruption to the customer.

With the battery system, commercial and industrial customers can save up to 40% on their electricity bills.

Convergent is said to have become the largest operator of energy storage in the Canadian province with 26MW of energy storage assets. IHI Energy Storage has another 21MW contracted in the region.

Wind energy company Infigen Energy plans to install a 52 MWh Tesla Powerpack battery energy storage system in South Australia.

The battery system will be next to its 278 MW Lake Bonney Wind Farm near Mount Gambier.

The Battery Energy Storage System (BESS) will cost around $38 million to build and install. ARENA and the South Australian government will each contribute funding of $5 million towards the project.

Once built, BESS will be connected to the National Energy Market. It will also enable Infigen to firm up an extra 18 MW of renewable supply.

Tesla Powerpack battery: a more reliabile energy supply

Infigen’s CEO Ross Rolfe said the project will allow the company to enter into additional commercial projects in SA, which he described as being “at the heart” of the company’s strategy.

Rolfe added that BESS demonstrates Infigen’s progress in delivering on its strategy. This includes contributing towards improved energy security and reliability of supply.

SA Energy Minister Dan van Holst Pellekaan said the government is a strong supporter of battery storage to harness the state’s abundant renewable energy. He added that more battery storage will deliver lower prices to households and businesses.

Other options considered prior to BESS

According to an AFR report, Infigen examined other options to improve energy supply reliability, such as pumped hydro and gas. However, the company decided on battery storage because of the state’s dependence on renewable energy supply.

The company also acknowledged that BESS would not have been possible for the company without the $10 million funding it received.

Battery energy storage systems shore up home supply too

Installing a storage battery in this way stores renewable energy such as wind and solar power for later use. This could be at night or during high electricity demand periods. This applies not only to commercial and industrial projects, but also to households and small businesses with solar installations.

With home solar battery storage in place, the solar power generated during the day can be stored and used after dark. This helps to improve clean energy reliability and supply on the home front, as well as drastically reduce electricity bills.

A new lithium-ion based energy storage system for ships has been launched by Rolls-Royce.

Dubbed SAVe Energy, it is said to be cost competitive and highly efficient that can be scaled depending on the energy and power requirements of the ships.

According to Rolls-Royce, a vessel can operate on batteries alone when in harbour or for a limited period with zero emission, depending on the specified battery capacity, with energy storage providing load smoothing and reducing the number of generators required to be operating.

It has been developed in partnership with ship firms Color Line, Norled and the Norwegian Coastal Administration Shipping Company, ensuring the system covers a wide variety of marine applications, including ferries, cruise vessels and multi-purpose vessels.

The development work was partly funded by the Norwegian Research Council of Norway’s ENERGIX programme.

Rolls-Royce has been delivering energy storage systems since 2010, however, the actual energy storage units were previously supplied by an external party.

Andreas Seth, EVP Electrical, Automation and Control – Commercial Marine at Rolls-Royce said: “The electrification of ships is building momentum. From 2010, we have delivered battery systems representing about 15MWh in total. However, now the potential deployment of our patent pending SAVe Energy in 2019 alone is 10-18MWh.

“Battery systems have become a key component of our power and propulsions systems and SAVe Energy is being introduced on many of the projects we are currently working on. This includes the upgrade programme for Hurtigruten’s cruise ferries, the advanced fishing vessel recently ordered by Prestfjord and the ongoing retrofits of offshore support vessels.”

New battery technology that could see electric vehicles being charged in a fraction of the time of current standards – and powered by either electricity or hydrogen – has been developed by a team of Scottish scientists.

Battery storage or fuel cell storage – this is a polarising topic for those in the game of developing electric car technology.

While a battery electric vehicle has the advantage of instant torque, quiet ride and zero tailpipe emissions, currently the speed with which an electric car can recharge is at best 30 minutes on a fast charger, or more often overnight if charged through a standard 3 phase outlet.

Hydrogen fuel cell technology – which stores the energy for the car in the form of hydrogen – is also tailpipe emission free, and while theoretically a fuel cell vehicle can be refuelled as quickly as a petrol or diesel vehicle, the technology is far more expensive.

Now, researchers at the University of Glasgow say they have created a flexible solution using nanomolecules that allow energy to be stored and output in the form of either electricity or hydrogen gas.

The breakthrough uses what the researchers are describing as an ‘exotic rust’ – a metal oxide that when added to water, can be charged with electricity.

Using this technology – which is still in prototype stage – EV drivers would be able to refuel cars in much the same way as is done at the petrol station today.

First, the used ‘rust’ liquid is removed using a special nozzle at the pump, then the car is refuelled using a second nozzle to replenish the car’s energy stores.

Professor Leroy Cronin, Regius Chair of Chemistry at the University of Glasgow, has published the breakthrough research in the journal Nature Chemistry and says the ‘flow’ liquid battery could be the answer to making EVs a real contender against fossil-fuel vehicles.

“Energy storage solutions that can act as both batteries and fuel generation devices (depending on the requirements of the user) could therefore revolutionize the uptake and use of renewably generated energy,” wrote the researchers in the journal.

It may not be smooth sailing for Pacific Gas and Electric’s landmark energy storage projects.

Totaling 567 MW, 2,270 MWh, the four projects were hailed as the largest battery storage investment ever proposed when PG&E submitted them for approval at the California Public Utilities Commission (CPUC) in late June. However, comments opposing the projects could slow down their approval and implementation.

Already, the state’s Office of Ratepayer Advocates (ORA) and the Direct Access Customer Coalition (DACC) have filed comments opposing the projects, prompting the CPUC to extend the approval process by at least 120 days. The comments raise questions about whether or not the energy storage projects are needed and whether PG&E’s proposal conforms to the commission’s directives.

The recently-filed comments have had very little public scrutiny, as they were only sent to the relevant parties and have not been posted on the CPUC website.

The cost of reliability

In their comments, the ORA, which is part of the CPUC, argues that the energy storage projects are not needed because the deficiency they are designed to fill will be met with new and planned transmission projects. The ORA claims the projects do not comply with CPUC resolution (E-4909) that authorized PG&E to issue a solicitation for the projects.

The resolution is designed to alleviate the need for an out-of-market contract for Calpine’s Metcalf Energy Center, a 564-MW gas-fired plant in San Jose. Calpine had told the California ISO that it would have to take the plant out of service because it was uneconomic, but the ISO determined the plant is needed, granting a reliability must run (RMR) contract.

In the resolution authorizing the storage projects, the CPUC expressed its concerns about the impact the RMR contracts would have on ratepayers and the lack of competition in the RMR process that can lead to “market distortions and unjust rates for power.”

The commission ordered PG&E to enter into energy storage contracts at “reasonable cost to ratepayers” and to take into consideration the cost and value and the results of previous, similar solicitations. But the ORA argues PG&E did not meet the CPUC’s requirements because the utility did not provide “analysis or explain how the cost of the four energy storage projects are reasonable taking into consideration the cost of the Metcalf RMR contract.” Nor did PG&E compare the four contracts to previous energy storage solicitations, the ORA said.

Customer Energy Management programme to be paid for through shared savings