Across the country, increased energy storage deployments are being spurred by customers looking to gain more control over their energy bills and utilities aiming to build resilience and flexibility into their grid operations.

Grid flexibility has always been important, but its significance continues to grow as more and more variable generation is added to the grid — primarily in the form of wind and solar.

Storage acts as a buffer to absorb and offset the changing energy supply and demand. As a result, 431 MWh of energy storage was installed in the U.S. in 2017, and nearly three times that amount (1,233 MWh) is expected in 2018, according to GTM.

Energy storage has arrived. It’s gone from a nice-to-have to a must-have for utilities that are integrating renewables on the grid. For utilities navigating how to integrate storage into their planning, here are a few things to consider.

1. Look for grid congestion

In some parts of the grid, transmission capacity has not kept pace with growing end-user demand due to an increase in renewables and distributed energy resources. Strategically placing storage along demand-strained transmission or distribution systems can not only improve performance of these systems, but also help delay or even avoid costly upgrades.

Think of it this way — to add more capacity to a transmission system often requires a full replacement of wires and transformers to deliver more power to a node on the transmission or distribution (T&D) system. Energy storage has the ability of clipping the peak demand on that system, shown in the figure below as “overload,” allowing the existing transmission and distribution system to be used.

For example, Arizona Public Service installed a 2 MW, 8 MWh battery arrayinstead of rebuilding 20 miles of transmission and distribution lines last year. The energy storage project will delay transmission investments for three to six years and has been deemed “very, very cost-effective.”

Vistra, which emerged from the bankruptcy of Energy Future Holdings and recently completed the acquisition of Dynegy, said last year that it will close 4.2 GW of Texas coal capacity. Despite that, the company has said it has no plans to build new plants and will instead look to optimize its remaining fleet.

At a June 12 analyst meeting, Morgan said he is “happy with what we have in conventional generation.”

The Upton 2 battery project is expected online in the fourth quarter of this year to soak up renewable energy that would have been wasted.

“With batteries, some of this extra generation will be captured and discharged at peak times,” the company explained in a presentation. “Batteries can also be charged from [the] grid at low power prices (i.e., at night) and discharged in the morning.”

The project should have attractive returns because of its eligibility for the Investment Tax Credit and bonus depreciation, its ability to use excess solar generation, and energy arbitrage opportunities, Vistra told analysts.

In the near term, batteries are “most likely to threaten investment in new peaking plants … short duration storage may allow peaking plants to provide non-spinning reserves,” Vistra noted in its presentation.

A GTM Research report released in March concluded a third of new gas peaker capacity will be at risk from four-hour energy storage by 2027. The report said 20 GW of new peaking capacity are forecast to come online by 2027.

The founder and CEO of Off Grid Energy has stressed the importance of battery storage and smart charging systems as the take up of electric vehicles (EVs) increases.

According to Danny Jones, the power demand from charging electric vehicles is too great for the already buckling London power grid.

Earlier this year, UPS – in conjunction with UK Power Networks Services – installed Off Grid’s UBESS system which had the task of reinforcing the local grid using battery storage to allow the powering up of the company’s fleet of EV delivery vehicles from the current limit of 65 to all 170 vehicles at its Camden depot.

Jones said: “The primary issue with the Camden installation was that the incoming grid supply was insufficient to support the additional power demands of the new fleet of EVs. The cost of re-enforcing the grid at the substation jeopardised the business case for full electrification of the fleet.”

Jones says that Issues such as these are not exclusive to UPS – EV applications are demanding more power and they need it now. Logistics operations and bus companies are looking to electrify their fleets to help in the fight against air pollution and climate change but are often held back by a lack of grid capacity.

“At Off Grid, we have the ability to install and have energy storage solutions up and running in a matter of weeks and bring the benefits of battery storage to the fore,” added Jones. “The benefits of deploying these systems are manifold and are absolutely necessary to prevent a delay in EV deployment because of the cost and lead-in times to reinforce the electricity network at substations, not to mention they can start working right away with minimal installation time needed.”

The UBESS battery storage solution from Off Grid can perform other capabilities over and above the primary function of enabling the introduction and maintenance of the EVs.  For example, when the depot does not need the power, the unit has the ability to provide energy back to the grid for DSR (demand side response) which is a monetizable service for the electricity network operator.

“Battery storage and smart charging systems like UPS Camden are already being adopted in other industries such as bus companies, materials handling corporations, multiple occupancy buildings as well as the car rental sector. Rapidly deployable smart-charging and storage systems are an absolute necessity for cities to reap the benefits of EVs,” concluded Jones.

A crew of battle-tested cleantech veterans raised serious cash to solve the thorniest problem in clean energy.

As wind and solar power supply more and more of the grid’s electricity, seasonal swings in production become a bigger obstacle. A low- or no-carbon electricity system needs a way to dispatch clean energy on demand, even when wind and solar aren’t producing at their peaks.

Four-hour lithium-ion batteries can help on a given day, but energy storage for weeks or months has yet to arrive at scale.

Into the arena steps Form Energy, a new startup whose founders hope for commercialization not in a couple of years, but in the next decade.

More surprising, they’ve secured $9 million in Series A funding from investors who are happy to wait that long. The funders include both a major oil company and an international consortium dedicated to stopping climate change.

“Renewables have already gotten cheap,” said co-founder Ted Wiley, who worked at saltwater battery company Aquion prior to its bankruptcy. “They are cheaper than thermal generation. In order to foster a change, they need to be just as dependable and just as reliable as the alternative. Only long-duration storage can make that happen.”

It’s hard to overstate just how difficult it will be to deliver.

The members of Form will have to make up the playbook as they go along. The founders, though, have a clear-eyed view of the immense risks. They’ve systematically identified materials that they think can work, and they have a strategy for proving them out.

Wiley and Mateo Jaramillo, who built the energy storage business at Tesla, detailed their plans in an exclusive interview with Greentech Media, describing the pathway to weeks- and months-long energy storage and how it would reorient the entirety of the grid.

The team

Form Energy tackles its improbable mission with a team of founders who have already made their mark on the storage industry, and learned from its most notable failures.

There’s Jaramillo, the former theology student who built the world’s most recognizable stationary storage brand at Tesla before stepping away in late 2016. Soon after, he started work on the unsolved long-duration storage problem with a venture he called Verse Energy.

A small investor-owned utility in New Hampshire may be on the verge of regulatory approval for one of the most ambitious U.S. tests yet of utility-owned, customer-sited battery energy storage systems.

In the process, regulators and stakeholders of the DE 17-189 proceeding are wrestling with a question of vital interest to the rest of the 3,000-plus U.S. utilities: Should a utility own customer-sited storage or is it a distributed energy resource (DER) that should be left to private sector providers?

Utilities have already seen the benefits that large-scale battery energy storage offers in shaving peak demand, providing grid services, and making systems more flexible. There is a clear opportunity to use customer-sited battery storage in the same way. But the question of how far utilities can intrude into markets so far served by private sector vendors must first be answered.

Vermont goes first

The only major U.S. utility-owned, behind-the-meter (BTM) battery storage is the Green Mountain Power (GMP) pilot project, according to GTM Research Energy Storage Analyst Brett Simon. GMP, the dominant Vermont electricity provider, is installing 2,000 behind-the-meter Tesla Powerwalls that will provide dispatchable energy and other grid services to New England’s wholesale electricity markets. Customers pay a one-time $1,300 fee or a monthly $15 fee to participate.

New Hampshire’s Liberty Utilities wants state regulators to approve a pilot project of 1,000 utility-owned Tesla Powerwalls. They would be provided to customers for a one-time $1,000 fee or a monthly $10 fee.

Approximately 300 would be installed in homes along a circuit where Liberty wants to test the viability of a non-wires alternative to a distribution system infrastructure upgrade. The other 700 batteries would be available to customers who apply to participate in the pilot.

Like GMP, Liberty would use the BTM storage to reduce its customer base’s costs for power market peak demand charges and to provide other system services. Liberty would also use the pilot to introduce a new time-of-use (TOU) rate to support customer participation.

Private sector DER providers and the New Hampshire Public Utilities Commission (NHPUC) Staff say the pilot should not be approved. Solar and storage providers Sunrun and ReVision Energy argue Liberty customers would benefit more by working through the private sector. Staff argues the proposal is too costly and not technically workable.

The US Army is behind a new research project at the Department of Energy’s Brookhaven National Laboratory that aims to send lithium-ion batteries spinning into a new era of high capacity energy storage. Among other things, that means more wind and solar grid integration, and that’s kind of funny considering that right now DOE is making yet another stab at finding a way to save old coal and nuclear power plants from the dust bin of history. Good luck with that!

Energy storage really is the key to renewable energy grid integration, so let’s take a look at the new Brookhaven research and see what’s up.

High Capacity Energy Storage, With Iron

Earlier this week, CleanTechnica made the case that we are entering the Age of Nickel, but perhaps we spoke too soon. The new Brookhaven lithium-ion battery owes its superior performance thanks to the Age of Iron, or rather iron trifluoride.

Iron trifluoride doesn’t usually pop up when the topic turns to energy storage in general and increasing the capacity of lithium-ion batteries in particular, and for good reason. Here’s the lab with an explainer:

…the compound has not historically worked well in lithium-ion batteries due to three complications with its conversion reaction: poor energy efficiency (hysteresis), a slow reaction rate, and side reactions that can cause poor cycling life.

In other words, the battery is not particularly rechargeable. That sounds like a hopeless case, but on the other hand iron trifluoride is relatively inexpensive and it’s non-toxic, too. Brookhaven chemist and lead researcher Enyuan Hu offers another good reason to pursue the compound for more and better energy storage:

The materials normally used in lithium-ion batteries are based on intercalation chemistry. This type of chemical reaction is very efficient; however, it only transfers a single electron, so the cathode capacity is limited. Some compounds like FeF3 are capable of transferring multiple electrons through a more complex reaction mechanism, called a conversion reaction.

Work has started on the first multi-megawatt battery storage project in Germany.

RES Deutschland is building the 10 MW project for utility VBB in the German municipality Bordesholm.

The battery storage will provide grid stabilization and back-up power fed from 100 per cent renewables to Bordesholm if there is a main grid disruption or upstream grid failure.

Bordesholm currently meets 75 per cent of its electricity demand from renewables which are directly connected to the grid. VBB is aiming to raise this figure to 100 per cent by 2020.

In addition to providing control power, VBB’s battery with a storage capacity of 15 MWh can continue to provide power to Bordesholm if there is a grid outage.

VBB Managing Director Frank Günther said: “This is a unique solution for an island network linking into a public power supply network. With this smart solution, the use of coal and nuclear power plants can be avoided in the future. New, modern battery storage plants can ensure the required system stability by using only renewable energy.”

The Bordesholm project is funded as a pilot project by the EU and the state of Schleswig-Holstein, which is promoting the development of storage technologies.

“With this standalone solution, the battery storage becomes a flagship project, which forms a very important component on the way to a supply from 100 per cent renewable energy,” said Dominique Guillou, managing director of RES Deutschland.

Matthias Leuthold, head of energy storage at RES Germany, added: “Battery storage systems are central elements of the German Energy Transition 2.0. In the coming years, due to the increasing displacement of thermal power plants by renewable energy sources, the provision of primary control power with battery storage systems will continue to gain importance in Germany.”

The VBB-project is the first multi-megawatt battery storage project in Germany. The commissioning of the battery storage is scheduled for spring 2019. After the completion of this pilot project, research institutions and universities will be able to use the data generated from the battery storage to transfer new findings to other network projects.

As the largest state-owned public utility in America, in one of the most progressive states in the country, the New York Power Authority doesn’t have the option of taking a “wait and see” approach on cleantech.

Plus, NYPA’s business model enables it to invest in and deploy new technologies in bold ways, according to President and CEO Gil Quiniones.

New York’s investor-owned utilities are also deploying innovative technologies. But NYPA can generally take more risks and move faster because it doesn’t have to go through the Public Service Commission’s regulatory process.

“We tend to be able to be the first mover and the first tester of new initiatives,” Quiniones said.

GTM spoke with Quiniones last week for an update on NYPA’s 2020 strategic plan, ahead of his keynote interview with Shayle Kann, senior vice president at Energy Impact Partners, at the Grid Edge Innovation Summit taking place June 20-21 in San Francisco.

One of Quiniones’ top priorities is rolling out NYPA’s major new investment in EV infrastructure.

Last month, the public utility announced up to $250 million for EV-related investments over the next seven years. NYPA’s board of trustees has already approved $40 million for specific investments between now and the end of 2019, including around 200 DC fast chargers along major thoroughfares, the installation of EV chargers at New York’s JFK and LaGuardia airports, and the establishment of “model communities” to test various customer engagement programs.

“NYPA is interesting because we serve 47 municipal utilities and four cooperatives (these are small distribution utilities owned by cities or towns). So we will pick two or three to…test various customer engagement strategies to see what sticks in terms of promoting adoption for electric vehicles,” said Quiniones.

How NYPA will spend the remaining $210 million to be deployed by 2025 has yet to be determined. That decision will depend a lot on lessons learned from the first phase of the program, Quiniones said.

A chemical compound commonly used to boost crop yields could be the answer to helping the world increase its consumption of renewable energy.

In a world first, Siemens is opening a £1.5m pilot project in Oxfordshire employing ammonia as a new form of energy storage.

The German industrial firm hopes to prove that ammonia can be as useful as more established storage technologies, such as lithium-ion batteries, when it comes to managing the variable output of wind and solar power.

The proof-of-concept facility at Harwell will turn electricity, water and air into ammonia without releasing carbon emissions. The ammonia is stored in a tank and later either burned to generate electricity, sold as a fuel for vehicles or for industrial purposes, such as refrigeration.

Dr Ian Wilkinson, programme manager for Siemens’ green ammonia demonstrator, said: “Storage is recognised as the enabler for intermittent renewable power.

“This is where we’re different from usual storage, we’re not just looking at power. Usually it’s [storage] just filling in the gaps when the sun’s not shining and the wind is not blowing. We’re looking at other uses, mobility and industrial uses.”

Siemens believes ammonia has an advantage other over emerging storage technologies, such as “liquid air” and flow batteries, because it is repurposing existing technology and hardware.

The world produces about 170m tonnes of ammonia a year, the vast majority of which is used by farmers as fertiliser. Most of that is made from natural gas, emitting greenhouse gas in the process, but the Harwell plant does not use fossil fuels.

In a world first, the UK recently saw a liquid air energy storage (LAES) plant switched on in Bury near Manchester, soaking up excess electricity generated by an adjacent landfill gas facility for later use.

It marks the first time the nascent technology has been deployed commercially, and developer Highview Power believes LAES could soon rival other technologies such as batteries in the rapidly growing global energy storage market.

Capable of lasting for up to 40 years, LAES operations have a much longer lifespan than most batteries, and the technology has the potential to play a key role as the global electricity system shifts ever more towards clean, intermittent and renewable forms of generation.

The technology works by cooling air to -196C to turn it into liquid form, allowing it to be stored in high pressure tanks. When extra power is needed, the liquid is pumped and heated to turn it back into a gas, where it can be used to drive electricity turbines.

According to Bloomberg New Energy Finance, the global energy storage market could double in size six times over the next decade or so, growing to a cumulative 125GW/305GWh and attracting $103bn in investment by 2030.

Highview Power therefore hopes to be at the forefront of the energy storage boom, and is currently planning to add another LAES site in the UK in the near future.

Could the technology in the future rival batteries as a realistic, low cost and scalable proposition for the burgeoning energy storage market? BusinessGreen went to have a look.