October 23 (Renewables Now) – New York regulators have given the green light to a plan calling for the construction of a 316-MW energy storage system at the site of an ageing power plant in Long Island City.

The Certificate of Public Convenience and Necessity was issued by the New York State Public Service Commission (PSC) last week, moving the state closer to achieving its clean energy targets. This includes a goal of having 3 GW of energy storage capacity by 2030.

Planned to be partially operational by March 2021, the Ravenswood lithium-ion battery system will provide peak capacity, energy and ancillary services, and will also offset “carbon-intensive” on-peak generation that will improve the grid reliability in New York City.

The proposed system was developed by LS Power’s Ravenswood Development LLC and is expected to be able to store electricity that will supply more than 250,000 homes over an eight-hour period. The stored power will be discharged under New York Independent System Operator’s (NYISO’s) and Consolidated Edison Inc’s (NYSE:ED) dispatch orders.

LS Power said that the project was accepted in the NYISO 2019 interconnection facility study process and is “well-positioned” to meet a 2022 in-service requirement. It also took in a 300-MW Request for Proposals (RfP) that Con Edison issued this summer, which also requires projects to be switched on by end-2022.

Advanced battery technology company Saft has executed its first projects in Australia, installing around 2MWh of battery energy storage systems (BESS) at 13 sites in Queensland.

Electricity distribution network operator Ergon Energy has decided to adopt Saft’s lithium-ion energy storage systems to meet customer needs at fairly remote locations in Queensland, with the systems to be deployed over four years.

While Saft recently launched a 2.5MWh, much larger containerised ESS product, for the Ergon deal, the European battery company has deployed 20 separate Saft Intensium Mini lithium-ion energy storage systems (ESS), each of 100kWh capacity and 25kVA power “up to 800V in harsh environments,” Saft said.

Ergon currently uses single-wire earth return (SWER) cabling to reach customers a long way from the grid. SWER, which uses a single cable that also acts as the earthing, is in wide use in Australia and New Zealand. In a 2016 interview on Ergon’s corporate blog, company innovation engineer Stephen Richardson said that Ergon manages more than 164,000km of SWER.

In order to support the operation of the grid, including SWER cabling, Ergon is rolling out its own Grid Utility Support System (GUSS), which Richardson described as a “network-side energy storage product,” and said that the first 20 sites being developed with GUSS have been chosen by the distribution company as “the most needy areas for initial deployment”.

Saft’s battery systems have therefore been incorporated into Ergon’s GUSS proposition, with the battery company claiming the Ergon Energy Network ordered the GUSS to be deployed as a “cost-effective alternative to traditional augmentation on SWER networks”.

The batteries charge up during times of low demand and reinject power to the grid when demand peaks. Energy demand spikes in remote Queensland can be related to anything from energy-intensive farming to household peak demand in the evenings, and the SWER networks have been vulnerable to capacity and voltage constraints as a consequence, Saft said.

UK liquid air energy storage (LAES) start-up Highview Power said its first ever 250MWh ‘Cryobattery’ installation will be placed at the site of a decommissioned thermal power plant in the North of England and could be Europe’s largest ‘battery’ system when completed.

The company is a designer and manufacturer of liquid air energy storage (LAES) systems and claims that the technology enables the safe and reliable storage of energy at large scale and long durations, without requiring significant scale-up in costs. Company CEO Javier Cavada wrote a technical paper about the LAES systems and their economic appeal for our journal PV Tech Power earlier this year.

Highview has been in the public eye over the past few months after Energy-Storage.news in June reported that several 50MW / 250MWh sites are in development in the company’s homeland, as well as the potential for development in the US.

“We will start construction next year, we have commenced agreements, we have the firm services to be provided to National Grid and it will be the largest battery system in Europe at 250MWh,” Highview Power’s Javier Cavada told Energy-Storage.news yesterday.

Keeping the decommissioned power plant site ‘on the map’
The project is planned as the first of five of the same size to be developed in the UK by Highview, and Cavada said the choice to replace a fossil fuel plant site on the grid was instrumental.

“We will be using the same connection and the same electrical infrastructure [as the thermal plant], so there is no need to make [new] transmission lines. So where we are they are decommissioning a fossil fuel plant, we will use the same point of [grid] connection for the cryobattery.”

The LAES system will perform many of the same tasks that the thermal plant has done, as well as “getting electrons from the grid that are hopefully more and more renewable every day and shifting them to the right moment to meet demand,” and will be able to provide voltage support, inertia and other services to the grid.

Spanish renewables company Acciona has inked a deal to acquire 3GW of PV projects and 1GW of energy storage from US independent power producer Tenaska.

The deal includes 20 projects in the Southwest Power Pool and Southwest Power Pool markets, spanning the states of Pennsylvania, Ohio, Kentucky, Illinois, Kansas, Oklahoma, and Missouri. Acciona expects that eight projects, totalling 1.5GWp – or 1.2GW of rated power – to be in service by the end of 2023.

Tenaska’s development services arm, Tenaska Solar Ventures, will work alongside Acciona on project development.

The new solar plants will plump Acciona’s North American renewables portfolio, which is currently heavily weighted towards wind. The Spanish firm’s US solar activity is currently limited to a 64MW concentrated solar plant (CSP) in Las Vegas.

Rafael Esteban, Acciona’s North American energy division director, said that the new solar and storage capacity will give the company the “opportunity to increase our commitment to renewable energy and sustainability in the United States through photovoltaic and energy storage technology, after the investments we have already made in wind power.”

In a statement, Acciona said it counted 1,207MWp of solar capacity worldwide at the end of the first quarter of 2019.

Nebraska-based Tenaska is no stranger to inking megadeals. In November 2018, the Nebraska-based IPP signed an agreement with Swiss asset management company Capital Dynamics to develop 2GW of solar across the Midcontinent System Operator (MISO) market.

Supporting New York’s state goals of reaching 3,000MW of energy storage by 2030 – equivalent to 40% of today’s electric demand – codes for the safe installation of energy storage systems (ESS) will go into effect on a permanent basis after 1 November.

The issue of fire safety in relation to the deployment of stationary energy storage systems in New York, particularly in the US state’s densely populated urban areas, has been considered to have held back what has otherwise been a hugely fertile state for clean energy. New York State Energy Research and Development Authority (NYSERDA) statistics showed that as of September this year there were only 51 installed ESS in New York (not including New York City) with a total storage capacity of 74,600kWh.

Energy-Storage.news recently spoke with NEC, provider of the state’s first, 20MW, grid-scale battery system and Key Capture Energy, the project’s developer. Both parties said that there had been a lot of work to do in getting that ESS up and running, including a great deal of work in close partnership with the Fire Department. NEC’s Roger Lin also said that he had been one of around 50 industry stakeholders to have contributed to the US National Fire Protection Association (NFPA) draft energy storage standards, published in September this year.

In June, the New York State Department of State issued its 2019 Energy Storage System Supplement which included amendments to the New York State Uniform Fire Prevention and Building Code, as well as pertinent amendments to the 2015 International Fire Code and 2015 International Building Code, both widely used across the world and now adding relevant definitions for different energy storage system technologies and terms.

Fire Department takes lead on issuing guidance
At the beginning of October, the Fire Department issued guidance on the design, installation and emergency management procedures for outdoor stationary storage battery systems, noting that “various highly-publicised incidents have illustrated the fire safety concerns associated with lithium-ion batteries. In addition to lithium-ion, the new stationary storage battery technology includes nickel-cadmium, nickel metal hydride and flow batteries,” the Fire Department’s rule said.

Britain’s cheapest “virtual battery” could be created by hoisting and dropping 12,000-tonne weights – half the weight of the Statue of Liberty – down disused mine shafts, according to Imperial College London.

The surprising new source of “gravity energy” is being developed by Gravitricity, an Edinburgh-based startup, which hopes to use Britain’s old mines to make better use of clean electricity at half the cost of lithium-ion batteries.

Gravitricity said its system effectively stores energy by using electric winches to hoist the weights to the top of the shaft when there is plenty of renewable energy available, then dropping the weights hundreds of metres down vertical shafts to generate electricity when needed.

The scheme mimics hydropower projects which have played a key role in helping to balance the electricity grid since the Dinorwig project in Wales began operating in the mid-1970s.

Charlie Blair, Gravitricity’s managing director, said: “The beauty of this is that this can be done multiple times a day for many years, without any loss of performance. This makes it very competitive against other forms of energy storage – including lithium-ion batteries.”

A full-scale project would drop 24 weights totalling 12,000 tonnes to a depth of 800 metres to produce enough electricity to power 63,000 homes for more than an hour.

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By carefully controlling the winches Gravitricity said it could extend this period by allowing the weights to fall at a slower rate and release electricity over a longer period.

The company is currently in discussion with mine owners in the UK, Finland, Poland, the Czech Republic and South Africa, where mine shafts could be more than 2,000 metres deep.

Oliver Schmidt, the lead author of Imperial’s report, said Gravitricity’s model is the most price competitive energy storage option because it has a relatively low upfront cost and a potential lifespan of more than 25 years.

In a deal spanning 20 projects, seven states, two power markets and more solar than the entire state of Florida has installed to date, ACCIONA has agreed to a deal with Tenaska to acquire 3 GW of utility-scale solar and 1 GW of co-located solar and energy storage.

This represents one of the largest deals known to pv magazine. What’s more is that the projects aren’t all that far from going on-line, CEO of ACCIONA’s Energy Division in North America, Rafael Esteban boldly shared: “We will bring a significant portion of the portfolio into service between 2021 and 2023.”

Specially, ACCIONA envisions commissioning eight projects by the end of 2023, adding around 1.5 GW of peak capacity to its North American renewable energy portfolio.

And, if we want to play the exponential capacity game, it seems as if this deal will set the record. Prior to this acquisition, ACCIONA’s entire American solar portfolio was comprised of just the 64 MW Nevada Solar One concentrated solar plant, just outside of Las Vegas. On the global scale, however, the company owns over 10 GW of renewable generation assets.

And while 3 GW of solar is massive, 1 GW of battery storage is, quite literally, unlike anything we have ever seen in the United States. To date, the country has only 899 MW of operating batter storage. And while that figure is anticipated to reach 1 GW by year’s end, even then this is 1/67th of the total installed solar capacity and an even smaller percent of installed renewable energy capacity.

In July, the U.S. Department of Energy’s Energy Information Administration (EIA) has released a report predicting that the volume of battery storage will more than double to 2,500 MW by 2023. Considering both the above goal of having the majority of this project pipeline in operation by 2023 and the size of the pipeline, this deal alone could help the United States achieve or, moreover, surpass that figure.

Now that wind energy has gone mainstream, the big challenge is how to squeeze the most kilowatts out of a wind turbine. The task is more complicated than simply increasing the size and efficiency of the turbine. People—and businesses—need electricity when they need it, but the wind blows when it will. The result can be an undersupply of wind energy during peak demand periods and an oversupply at other times, especially at night.

Until recent years, batteries and other energy storage systems were too expensive to help bridge the mismatch between supply and demand. However, more economical technology is coming online, and it’s having a powerful impact on both the wind and solar energy markets.

Meeting the wind energy challenge
Idaho-based KORE Power is one company tapping into the potential for scaling up the global wind industry through energy storage.

Lindsay Gorrill, CEO and director of KORE Power, explains that energy storage can help spur investor interest in wind farms, because it can significantly reduce the amount of time that wind turbines are idled or operating at a lower capacity due to oversupply.

“When you drive by a wind turbine and you see only one (or none) running, it means they are not utilizing the wind. Storage enables you to utilize that large capital you’ve spent,” Gorrill explains.

To be clear, energy storage is just one cog in the many gears of grid management, so there are other considerations in play. Nevertheless, the basic idea is that investment in a wind farm is more attractive when the capital is sunk into equipment that creates energy more of the time.

Estimates vary by a wide amount, but energy storage has the potential to enable wind farms to operate consistently at close to 100 percent capacity. Without energy storage, some wind farms barely operate in the double digits.

Bigger and better wind turbines
The benefits are coming into sharper focus not only because energy storage costs are falling, but also because wind turbine technology is improving.

The U.S. is already dotted with wind farms that are operating with older, less efficient turbines. Existing wind farm owners are seizing the opportunity to re-power their wind turbines with new technology. That provides an opportunity to scale up the energy storage component as well.

Gorrill also notes that energy storage technology, like wind technology, is evolving rapidly. Until recently, for example, lithium-ion battery technology has focused primarily on the electric vehicle market. That means finding a delicate balance between cost, efficiency, size and weight. In contrast, the stationary energy storage field can focus primarily on cost and efficiency.

KORE Power’s Mark 1 utility-scale battery illustrates the difference in approaches between mobile and stationary energy storage, and the company is already keeping an eye out for future iterations of the technology.

The energy storage market received a boost Oct. 17 when the Federal Energy Regulatory Commission (FERC) approved the first two compliance filings implementing Order 841, a rule the commission said is designed to eliminate market barriers to electricity storage.

Order 841 was enacted in February 2018. The measure directs regional power grid operators to establish rules opening capacity, energy, and ancillary services markets to energy storage, and affirms that storage resources must be compensated for provided services. (Read “5 Key Takeaways from FERC’s Recent Energy Storage Order” in the June 2018 issue of POWER.)

“Electricity storage must be able to participate on an even playing field in the wholesale power markets that we regulate,” said Neil Chatterjee, FERC chairman, on Thursday. “Breaking down these market barriers encourages the innovation and technological advancements that are essential to the future of our grid.”

Regional grid operators submitted the first compliance plans in December 2018. FERC’s orders Thursday concern the compliance filings of Southwest Power Pool (SPP), a regional transmission organization (RTO) that serves all or parts of 14 states, and PJM Interconnection, the RTO serving all or parts of 13 states and the District of Columbia. FERC found the two market operators mostly complied with Order 841, and said it largely accepted their filings, though the agency did provide additional directives for further action.

FERC on Thursday said it found that proposals from both PJM and SPP would for the most part enable electric storage resources to provide all services within their capability, and would allow those storage resources to be compensated for services in the same way as other resources. The commission also said the RTO’s filings recognize the unique physical and operational characteristics of electric storage resources. FERC directed both SPP and PJM to submit further compliance filings to address other issues within 60 days.

Joe Hall, a partner with global law firm Eversheds Sutherland, told POWER in an email Thursday: “The potential for cost-effective energy storage development and integration presents a once-in-a-generation opportunity. In my mind, there are four basic storage models, each implicating different federal and state regulatory issues. While it certainly includes battery technologies, the first model is in the tradition of large-scale pumped storage projects meant to satisfy significant native load obligations. The second model is smaller scale storage (often paired with renewable generation). These projects certainly can be used to satisfy native load obligations, but often are discussed in the context of merchant dispatch into organized ancillary services markets. The third model is storage as an alternative to a transmission upgrade. The fourth model is storage as an alternative to a distribution upgrade.

The government is seeking views on amendments to the treatment of energy storage within the planning system.

In the last consultation, it had been proposed that the 50 MW Nationally Significant Infrastructure Project (NSIP) capacity threshold should be retained for standalone storage facilities. However, following disagreement from respondents to the consultation, the government has changed its stance. This week’s consultation proposes that electricity storage, with the exception of pumped hydro, be carved out of the NSIP regime in England and Wales.

In order to support the continuing decarbonisation of electricity generation, as well as decarbonisation of other sectors like transport and heat, energy storage will become more and more crucial, so removing obstacles in this way is a positive and pragmatic move by the government. The additional cost and uncertainty under the current regime for battery storage schemes that might be construed as falling within the DCO regime has certainly hindered progress in this important sector of the energy market.