Canadian company Hydrostor has just received approval to build the first grid-scale compressed air energy storage system in Australia.

Hydrostor will deploy a 5MW / 10MWh system at a former zinc mine near Strathalbyn, South Australia. The advanced compressed air energy storage (A-CAES) project, expected to cost AU$30 million (US$21.09 million) in total, received development approval and has been welcomed in statements by local politicians including South Australia’s energy and mining minister, Dan Van Holst Pellekaan.

“This is another step in the transition of South Australia’s energy system by the integration of renewable energy into the grid to deliver cheaper, more reliable and cleaner energy,” van Holst Pellekaan said.

“A-CAES is a new energy storage technology for Australia that provides synchronous inertia, load shifting and frequency regulation to support grid security and reliability.”

The system is designed to use surplus electricity generated by nearby solar and wind facilities to run compressors. Air is also heated as it is compressed and stored underground. A Hydrostor video explainer can be seen below.

Caverns will be dug 240 metres below the Angas Zinc Mine site, repurposing the existing mine to store the compressed air, which then drives a generator to produce electricity. The system will be used to help the local electricity network deal with times of peak demand, by outputting energy to the grid when needed.

It’s expected to have a 30-year lifetime in operation, with the South Australian government supporting the project directly with AU$3 million in funding through its Renewable Technology Fund. The national Australian Renewable Energy Agency (ARENA) is also contributing, putting in AU$6 million of the total cost.

London-based Highview Power has contracted with Nebraska-based Tenaska Power Services to help develop up to four gigawatt-hour scale cryogenic energy storage plants in the U.S. over two years, with the first project expected to be developed in the ERCOT market.

Highview’s technology uses electricity to chill and liquefy air at -320°F, stores the liquid air in insulated, low-pressure tanks, and later exposes the liquid air to ambient temperatures to rapidly re-gasify the air, expanding it to 700 times its liquid volume, to power turbines to generate electricity. The firm notes that its system can be configured to also use waste heat and cold.

Highview has been operating a 5-megawatt cryogenic energy storage facility in Manchester, England since June 2018.

Highview Power says the levelized cost is $140/MWh for a 200 MW/2 GWh (10-hour) system, with no use of waste heat or cold. The firm adds that its technology permits “weeks’ worth of storage,” with the use of additional tanks.

For comparison, Lazard has estimated that battery storage has a levelized cost of $108 to $140 per MWh for a utility-scale PV-plus-storage application. All cost estimates are sensitive to the assumptions used, particularly the capital cost, and the cost of capital.

Highview sees ERCOT as a promising market because it is “a big wind market—we can co-locate with wind resources to store power during off-peak hours,” said Javier Cavada, president and CEO of Highview Power, in a pv magazine interview.

The cryogenic energy storage technology can support “intermittent renewable generation, energy arbitrage, peak shaving, ancillary services, transmission and distribution deferral, inertia services, reactive power, and voltage support,” he said.

Highview’s pilot-scale facility in England uses waste heat from adjacent landfill gas engines, said Mr. Cavada, and the technology can also use waste cold—for example, from an LNG import terminal, where liquified natural gas is being re-gasified to put on a gas distribution network. He said that LNG process may use sea water to warm the LNG, thus chilling the sea water, and “the cold is simply being dumped.”

General Electric is a big and sprawling company that’s undergone some dramatic reorganizations over the past few years, particularly in its renewable energy, energy storage and grid edge business lines.

But over the past four years, amid these large-scale corporate changes, a small unit of GE has built a growing business around developing distributed solar and solar-plus-storage projects.

On Tuesday, GE announced it’s taking this business to a new stage, via a partnership and majority investment by asset management firm and heavyweight renewables investor BlackRock Real Assets.

The new company, named Distributed Solar Development, will be 20 percent owned by GE Renewable Energy and 80 percent owned by a fund managed by BlackRock. The business, which has been incubated within GE since 2012, will focus on commercial, industrial and public-sector customers.

Erik Schiemann, CEO of Distributed Solar Development and a veteran of various GE business units, said in an interview that the investment would allow the company to expand its current project development work — and, for the first time, own the projects it’s developing.

“What we specialize in at Distributed Solar Development is the origination, development, design, execution, building, and asset management of distributed solar and storage projects,” he said. Most of its projects to date have been behind-the-meter.

“BlackRock’s investment further advances our growth in that platform, allows us to take on new markets, and allows us to double down in the markets we’re currently successful in.”

And while the business hasn’t owned any of the projects it’s developed to date, that’s set to change with BlackRock’s investment. “The cash infusion allows us to participate as an owner of the assets,” he said.

BlackRock’s push into distributed energy resources
BlackRock Real Assets has primarily invested in utility-scale renewables, with $5 billion invested in over 250 wind and solar projects with a total generation capacity of over 5.2 gigawatts. But it has made moves into distributed-scale solar projects this year, including April’s undisclosed investment into small-scale solar project owner CleanCapital.

Batteries are now one of a “huge variety of distributed energy assets capable of providing flexible capacity to the network”, but failure to manage them correctly will limit the market opportunities available, as well as the lifetime of the systems themselves, the data science head of UK flexible energy tech company Open Energi has said.

In a blog published last week on our sister site Current± Open Energi’s Robyn Lucas explains how the “cost-benefit of every action performed by a battery energy storage system has to be weighed in terms of battery degradation and lifetime, whilst continuously managing the state of charge to ensure system availability.”

Both the throughput and cycling capabilities of batteries are essential metrics in modelling how they are to be used and what sort of revenues they can earn. As well as a more general look at the market dynamics and the technologies her own company uses to take on increasingly merchant-driven opportunities, Lucas’ blog takes a deep dive behind the workings of the grid-scale battery installed in North London at the stadium of professional football club Arsenal.

Thought to be the UK’s “first behind-the-meter battery to be aimed primarily at wholesale energy trading,” the fully-automated and optimised battery installation uses the battery to supply energy to the stadium facilities at the most expensive times of day.

“At the same time, the system is generating revenue – split between Arsenal, [developer] Pivot Power and investor, Downing LLP – from energy arbitrage and imbalance opportunities,” Lucas writes.

Read the full blog Throughput vs Revenues: Making the most of battery storage, at Current±, Solar Media’s energy transition news and analysis site.

When the PJM Interconnection* proposed that energy storage needed 10 hours duration to qualify for capacity payments, that seemed to make no sense.

No other grid operator had proposed such a requirement—essentially disqualifying battery storage—in its plan for complying with an order from the Federal Energy Regulatory Commission to allow energy storage to participate in all markets where it is technically capable of doing so (including capacity markets).

Now we have an analysis that debunks PJM’s proposal.

Storage with 4-hour duration can provide up to 4,000 MW of capacity of “equivalent reliability value” to that supplied by conventional power plants in PJM, according to a study by Astrapé Consulting.

Astrapé used the SERVM model for its analysis, a model it has used for similar evaluations it has performed for other regional grid systems such as ERCOT, MISO, and SPP.

Astrapé’s report concluded:

A 4-hour duration requirement would correctly represent the capacity value of storage under current market conditions and would remain accurate until the amount of installed storage in PJM increases by two orders of magnitude.”

The “two orders of magnitude” refers to the 40 MW of 4-hour non-hydro storage that Astrapé determined is currently operating in the PJM region, compared to the 4,000 MW potential.

The capacity payments at issue are intended to ensure that adequate reserve capacity is available to meet demand at occasional times of extreme demand, such as extremely hot or cold days.

But when storage is excluded from the capacity market, that causes the market-clearing price for capacity to be higher, increasing customers’ electric bills. Meanwhile, lower compensation for storage can limit otherwise cost-effective deployments of solar and wind power, which pair well with storage.

In its analysis, Astrapé followed an elegant approach illustrated in Figure 1. In step 1 as shown, Astrapé modeled the addition of conventional capacity to reduce the “loss of load expectation” (LOLE) to 0.1, a “generally accepted reliability criterion” that “represents a single day of firm load shed in a 10-year period.” In step 2, Astrapé modeled the addition of energy storage, reducing LOLE below 0.1. In step 3, Astrapé modeled the removal of conventional capacity until LOLE was again 0.1. This yielded a ratio of storage capacity added to conventional capacity removed.

Georgia Power is set to boost its state’s battery energy storage sector, with the company’s plan to own and operate 80MW of battery energy storage now approved by the Georgia Public Service Commission (PSC).

Georgia Power’s 2019 Integrated Resource Plan (IRP) has been approved by the Georgia Public Service Commission (PSC), in a unanimous decision. The plan includes energy storage, 72% more renewable generation by 2024, and approval of the company’s environmental compliance strategy.

Allen Reaves, Georgia Power’s senior vice president and senior production officer, said: “Working with the Georgia PSC, we are positioning Georgia as a leader in the Southeast in battery energy storage, which is critical to growing and maximizing the value of renewable energy for customers as we increase our renewable generation by 72% by 2024.

“Through the IRP process, Georgia Power will continue to invest in a diverse energy portfolio including the development of renewable resources in a way that benefits all customers to deliver clean, safe, reliable energy at rates that are well below the national average.”

Under the approved IRP, Georgia Power will both own and operate the 80MW of new battery energy storage, add 2,260MW of new renewable generation to the company’s energy mix and retire five coal-fired units across the state.

New energy efficiency programs for customers, including both an income-qualified program and aniIncome-qualified energy efficiency pilot program, were also approved in this plan.

Georgia Power filed requests with the PSC to both raise residential rates and seek approval for its IRP earlier this month, while elsewhere in the US, utilities in New Mexico and Tennessee have also filed major new plans that include significant mention of energy storage.

Gas peaker plants may be among the first casualties of a new Minnesota law requiring utilities to include energy storage as part of their long-range plans.

The provision, part of an omnibus jobs and energy bill, “puts energy storage on a level playing field with natural gas plants and other resources,” said Ellen Anderson, executive director of the University of Minnesota’s Energy Transition Lab. “Utilities will have to acknowledge the capabilities storage can provide as an alternative to, say, a fossil fuel plant.”

The most likely victim could be peaker plants, which operate when utilities face high demand for short durations, such as hot summer days, she said.

A 2017 study commissioned by the Energy Transition Lab found that peaker plants are a “marginal resource for meeting capacity needs” and that storage, and solar-plus-storage, are “becoming increasingly cost competitive.” By 2023, the report predicts, the cost of storage becomes less than building new peaker plants.

Minnesota’s investor-owned utilities are in different phases of presenting their integrated resource plans before the state Public Utilities Commission. The first utility to unveil an integrated resource plan since the law passed is Xcel Energy, which included energy storage in its forecasts.

The major aspects of Xcel’s plan call for retiring all its remaining coal plants within the next decade, operating the Monticello nuclear plant until 2040, and adding 4,000 megawatts of solar and 1,200 megawatts of wind. The plan calls for the acquisition of one combined cycle natural gas plant and the construction of another, along with an aggressive energy efficiency program.

Xcel goals call for reducing carbon by 80% by 2030 and for producing no carbon through energy production by 2050.

Released July 1, the plan anticipates that energy storage in the 2030s will provide more dispatchable power and play a greater role supporting reliability. Price declines and technology advances between now and then will make utility-scale storage “an integral resource used to meet this need,” the report said.

At the same time, the report warns that energy storage has limitations in a system with much greater variability due to renewable generation. The answer to the problem of intermittency in renewable energy will not be energy storage.

“The current state of battery storage technology does not have the ability to match the duration of such events without significant (and very expensive) over-build of those resources,” the report states in an executive summary.

Colorado-based start-ups Simple Energy and Tendril have merged to create Uplight, a one-stop shop software platform for utilities’ customer-facing software needs, with ESS industry player AES Corporation taking a stake in the new company as a “strategic partner”.

The merger with Simple Energy is the latest in a rapid period of growth for Tendril, precipitated by securing a majority investment from American private equity firm Rubicon Technology Partners in December 2018. The home energy management start-up has since acquired FirstFuel Software, Energy Savvy and EEme.

The new company claims to be the first to unite all key solutions for delivery, management and optimisation of the customer energy experience, by bringing together leaders in utility-branded marketplaces, demand-side management, analytics and utility customer experience personalisation.

Uplight already provides software to more than 75 utility clients across 40 states, according to a company statement.

Rubicon Technology Partners will be the majority stakeholder in the combined company, while AES Corporation also has a significant stake; the Fortune 500 company was Simple Energy’s largest shareholder and made a US$53 million strategic investment in the new company as part of the merger.

The energy storage technology provider and system integrator emailed Energy-Storage.news with a statement that it has already used Uplight’s platforms in demand response and energy efficiency programmes and that “the AES teams that develop community solar and energy storage solutions will be working with Uplight to enhance their solution offerings around those technologies”.

Adrian Tuck, formerly CEO of Tendril, will be CEO at Uplight.

Also this week, British software company Smarter Grid Solutions (SGS) has also been finetuning its offering. It unveiled the advanced version of its popular distributed energy resource management system (DERMS) software ANM Strata on June 12. Equipped with advanced tools for data analytics, visualisation and application programming interfaces (APIs), ANM Strata 2.0 has the ability to connect to other software systems at utilities and the operators of distributed energy resources (DERs).

Energy-Storage.news received information last week on a handful of successful battery installations at commercial customer sites, from NantEnergy in the US and from Alfen in Europe.

The Netherlands-headquartered system integrator and technology provider Alfen has supplied a 2.5MWh battery energy storage system to the headquarters of Smappee, the energy management technology company which recently struck a deal to roll out its EV smart charging solutions globally.

Smappee, which claims to have already deployed over 70,000 EV charge units, is building a cleantech hub at its headquarters in Harelbeke, Belgium, dubbed ‘Snowball’. It includes an energy laboratory, housing a cleantech accelerator programme and flexible office space for cleantech companies including startups. The offices and facilities will be powered by a combination of different renewable and energy-efficient solutions.

Alfen’s energy storage system will enable Snowball to effectively self-consume solar energy generated onsite and to balance the load – including electric vehicle charging and grid-balancing services. At a future date, off-grid or islanding capabilities could be added, Smappee CEO Stefan Grosjean said. Alfen also created a new 5MVA grid connection at the Smappee site to connect with the local distribution grid, as well as delivering complete, integrated storage solution.

Energy costs savings, backup capabilities drive value for US customers
From the US meanwhile, NantEnergy, which towards the end of 2018 acquired the energy systems and services business of Japanese technology provider Sharp, has touted a recent track record of successfully executed projects for C&I customers in the US states of California and New Mexico.

Sharp’s SmartStorage platform, which NantEnergy acquired, has been used in a few high profile commercial projects in the US, with Jigar Shah’s Generate Capital among the developers and financiers to use them to deliver energy costs savings – and sometimes backup power – to customers.

BILLINGS — Construction on a $1 billion energy storage system in central Montana could start as soon as next year after its sponsors said Friday they reached a financing agreement with a Danish firm that invests in renewable energy.

Carl Borgquist, president of Bozeman-based Absaroka Energy, said the involvement of Copenhagen Infrastructure Partners of Denmark marks a significant step forward for the 400-megawatt project near Martinsdale.

Next up, he said, is to make arrangements with utilities or others interested in using the Montana facility to complement their own electricity generation.

“That’s our last step before we’re able to go under construction and start putting concrete and steel in the ground,” Borgquist said.

The Gordon Butte Pumped Storage Hydro Project was first proposed in 2010 and is intended to make wind turbines and other renewable energy sources more reliable , by storing the electricity they produce until it’s needed.

Described as a “hydro battery,” it would use excess power produced by wind farms or other sources to pump water from a reservoir uphill to a second reservoir. The water would be released during periods of high electricity demand, turning hydropower turbines to generate power.

Many utilities use power plants fueled by natural gas to fulfill a similar role. They’re needed to balance electricity across the power grid as demand rises and falls over time.

A spokeswoman for Copenhagen Infrastructure Partners confirmed the firm’s involvement in the project. Senior Partner Christian Skakkebaek said in a statement that pumped storage hydro “will be a key resource as the global transition to renewable energy continues to accelerate in states such as Montana.”

Construction could take up to four years and require 300 to 400 workers, Borgquist said. Once the project is operational, it will have a permanent workforce of two- or three-dozen employees, he said.

The Federal Energy Regulatory Commission issued a license for the facility in 2016.

There are more than 20 gigawatts of pumped storage capacity across the U.S., according to the National Hydropower Association. An additional 31 gigawatts of capacity have been proposed, primarily in Western states, according to the association.