Jason Dreisbach fields at least half a dozen calls every week from people trying to sell him a technology to lower his energy costs. As the owner of Dreisbach Enterprises, a cold-storage facility owner with operations in Northern California, he’s a popular target. Cold storage — from frozen food warehouses to grocery and restaurant refrigeration — has one of the highest energy costs of any industry; energy expenditures are usually second only to payroll.

Dreisbach endures sales pitches that run the gamut of energy solutions, from LED lighting to rooftop solar to fuel cells. When Viking Cold Solutions reached out in 2017 with a thermal energy storage technology, his interest was piqued because, even though he had many questions, “it was not a foreign concept,” he said. The battle in cold storage is not keeping things cold, but rather removing heat. “We are constantly fighting [British thermal unit] intrusion,” Dreisbach explained. Viking Cold offered something that aided in the battle.

Cold storage facilities have long been a target for energy-efficiency and demand-response programs because of their intense energy needs. And yet, these ubiquitous facilities have not been fully tapped for their energy savings or potential as flexible energy resources. Some promising companies with mechanically complex thermal energy storage solutions targeting the commercial sectors, including the cold chain, have exited the business or turned to software-based offerings only.

It’s a tough sell to get any business, especially grocers or frozen-food warehouses, to give up valuable square footage for any energy storage solution, or to put their customers’ products in jeopardy to save on costs. Because of this, Viking Cold has found that many of its potential clients have had limited success with demand-management participation. And until recently, most utilities have not actively sought out long-duration energy storage as part of their grid flexibility portfolio. Now, that is all changing.

A big target, easily overlooked
Viking Cold Solutions didn’t set out to develop a technology for utilities to tap as a grid resource. Its founder simply wanted to move more frozen foods more efficiently between Jacksonville, Florida and Puerto Rico for clients such as Sam’s Club. The patented solution leverages thermal energy storage to the benefit of frozen-food storage providers and utilities.

In simple terms, all thermal energy solutions involve the heating or chilling of water or another medium, which is then used to shift energy loads. In the case of Viking Cold’s technology, it also improves efficiency. Thermal energy storage is currently a small but growing portion of the behind-the-meter energy storage market, according to Wood Mackenzie’s energy storage analysts.

Honeywell and DTEK, Ukraine’s largest private-sector energy company, have announced an agreement to launch Honeywell’s Experion Energy Program in Ukraine, the core element of an initiative by DTEK to develop the country’s first grid-scale energy storage system. Honeywell’s Experion Energy Program enables industrial customers to develop large-scale battery energy storage systems.

The system will help maintain Ukraine’s energy system, enable the integration of renewables into the energy mix and decrease fossil fuel power generation. Moreover, the energy storage system will increase the flexibility of Ukraine’s power grid and help pave the way for the country to join Europe’s energy community (ENTSO-E) in the future. For further information see the IDTechEx report on Batteries for Stationary Energy Storage 2019-2029.

Honeywell and DTEK will execute the Experion Energy Program as a pilot project, based around a 1MW/1,5 MWh lithium-ion energy storage system located at DTEK’s Zaporizhzhya Power Plant. The manufacture, installation and commissioning of the system will take place during 2020-2021.

Commenting on the agreement, Emanuele Volpe, Chief Innovation Officer, DTEK, said, “The future of energy is focused on the transition from a centralized energy system to one that is decentralized and flexible, with an increasing focus on the provision of energy from multiple sources — including renewables. DTEK is the driving force behind changes that will determine the future of Ukraine’s energy sector, and this agreement with Honeywell exemplifies our commitment to leading the way on this national objective.”

Honeywell will supply DTEK with its Battery Energy Storage System (BESS) technology along with remote operations systems and its Experion Energy Control System. These technologies will enable automated, agile operations and help optimize dispatch of the BESS. The system’s batteries will function as operating reserves that constantly work to manage frequency fluctuations on the grid (Frequency Containment Reserve) and charging up during off-peak times and discharging when energy demand and electricity costs increase (energy arbitrage).

“Around the world, consumers, producers, utilities and grid operators are facing increasing pressure and expectation to manage energy consumption, reduce electricity costs and improve sustainability,” added Eren Ergin, General Manager, Renewables and Distributed Assets, Honeywell Process Solutions. “Our Experion Energy Control System will help DTEK become the pioneer in the Ukraine market by enabling it to create a bankable business model to manage energy storage assets and help balance the grid as the renewable energy mix increases in Ukraine.”

An explosion at an Arizona energy storage facility last year was started by a defective battery cell that overheated and caused a buildup of flammable gas, according to a report released Monday.

Firefighters unintentionally ignited the gas on April 19 last year when they opened a door to the facility located near Phoenix, Arizona, according to the report released by Pinnacle West Capital Corp.’s Arizona Public Service utility. The battery fire suppression system failed to stop the faulty cell from melting other nearby cells, leading to a so-called “cascading thermal runaway,” according to the report, dated July 18 and posted to the utility’s website Monday.

LG Chem Ltd., the South Korean firm that manufactured the batteries used in the facility, disputes the results of the report and is conducting its own investigation into the fire, a spokesman said by text message.

The explosion forced Arizona Public Service to halt plans to install 850 megawatts of battery storage on its grid, one of the most ambitious efforts by a U.S. utility at the time. It came after a series of fires at energy storage facilities in South Korea, a global leader in battery manufacturing and deployment. The energy storage industry has been working to address safety concerns about its equipment, which is seen as critical to helping making solar and wind power more reliable and ubiquitous.

The report on the Arizona storage facility said a lack of space between battery cells, inadequate ventilation for flammable gases and a lack of proper training for emergency response workers also contributed to the blast, which injured several firefighters.

Contributing Factors
The report made several recommendations including incorporating better system designs that can prevent dangerous chain reactions in faulty lithium-ion battery cell. Other recommendations include building systems with better ventilation and changes in emergency response procedures.

The battery facility was assembled by Fluence Energy, a joint venture between AES Corp. and Siemens AG, and used batteries supplied by LG Chem, according to the report. Arizona Public Service and Fluence didn’t immediately return requests for comment after normal business hours.

The UK electricity system is undergoing significant and rapid change. It has the world’s largest installed capacity of offshore wind, has effectively stopped generating electricity from coal, and has recorded a 20% drop in demand since the start of the COVID-19 pandemic.

However, this transition from traditional, reliable coal to weather-dependent wind and solar generation brings with it increasing challenges to match electrical supply and demand at every instant. This is where large grid-scale energy storage systems could help regulate and buffer supply and demand, and improve grid control.

The UK government recently announced the removal of planning barriers to building energy storage projects over 50MW in England and 350MW in Wales. This, the government feels, will enable the creation of significant new energy storage capacity. The UK currently has 1GW of operational battery storage units and an additional 13.5GW of battery projects under development at the planning stage.

This intervention by the government creates a planning environment that could enable the UK to reach its target of net zero carbon emissions by 2050. This could happen with either a high proportion of large-scale, centralised renewable generation, or with more of a priority on smaller community schemes such as locally owned wind turbines and solar panels. Batteries will, in particular, contribute significantly to the grid regulation of a further 30GW of offshore wind by 2030 (to achieve the UK target of 40GW of offshore wind by that year).

But pursuing ever larger, stationary battery systems may not be the optimal solution for the UK to have a renewable energy future. Instead, the answer could lie in the country’s garages and car parks.

As the UK has moved from fossil fuel to renewable energy electricity generation, CO₂ emissions from the energy supply sector have fallen from over 40% of the UK total in 1990 to 25% in 2019. This means the transport sector is now the largest emitter, producing a third of all UK CO₂ emissions.

For electric utilities like Consolidated Edison Inc.’s subsidiary Orange and Rockland Utilities Inc., battery energy storage is a key component of providing reliable power, but challenges remain for storage technologies as they develop across the United States.

In March 2019, the utility announced it had selected Key Capture Energy LLC (KCE) to plan, design, install and operate a 3-MW battery storage project adjacent to its Ladentown substation in Pomona, New York, U.S., that would enable the utility to delay building costly new infrastructure to accommodate energy use at its peak, which occurs only a few times a year.

MD Sakib, section manager for utility of the future with Orange & Rockland (O&R), said the battery storage project stemmed from the utility’s need for additional infrastructure to provide safe and reliable power alongside rapid load growth in the area. “Rather than building a brand-new substation, by leveraging these distributed energy resource technologies, what we’re doing is we’re deferring the build of brand-new substations for about 10 years or so,” he said.

Battery storage technology like that in O&R’s Pomona project is gaining traction in the industry. Dramatic and recent decreases in pricing, advances in technology and more attention to improving resilience are all factors contributing to the exponential growth in energy storage markets. However, challenges remain for storage technology as it develops across the U.S., including not having enough in-field operational data, getting buy-in at the local level, a lack of sophisticated modeling tools, difficulty in determining the value of storage and the need for wholesale market rules to continue changing to account for the total value that energy storage provides to the grid.

The Biggest Challenge

According to the Energy Storage Association’s (ESA) website: “Energy storage is an enabling technology.”

The website explains that storage augments such resources as wind, solar, hydro, nuclear and fossil fuels as well as demand-side resources and system efficiency assets. It is flexible as it can act as a generation, transmission or distribution asset — or even combine all of these in a single asset.

Energy storage, or the use of batteries to absorb electricity from the grid when it is plentiful and discharge it when it is scarce, is ready for the big leagues.

That was the implication of a ruling on Friday from the U.S. Court of Appeals for the D.C. Circuit that has been celebrated by renewable energy enthusiasts. A three-judge panel upheld a rule by the Federal Energy Regulatory Commission (FERC) that requires energy storage and distributed energy sources to be able to fully participate in the nation’s major electricity markets, freeing them from rules by state regulators and utility companies that energy storage advocates say limited the technology’s potential revenue.

It wasn’t the only sign in recent days that energy storage is maturing as a power source. Yesterday California regulators announced they had connected to the grid a battery storage system of 62.5 megawatts — enough to power more than 10,000 homes and the largest such device in the country. And earlier today the U.K. government said it would allow battery storage projects to bypass a lengthy planning rules at the national level, easing the way for more development.

Analysts believe that the D.C. Circuit Court ruling could clear the way for the development of up to 50 gigawatts of energy storage, which would equal a third of the country’s current total wind and solar capacity. FERC’s chairman, Neil Chatterjee, hailed the ruling and said that the rule change FERC first published in February 2018 — known as Order 841 — “will be seen as the single most important act we could take to ensure a smooth transition to a new clean energy future.”

Any electrical grid that wants to run on 100% renewable energy — as many, including California’s and Germany’s, plausibly could do in the not-too-distant future — will need to have lots of energy storage on hand to ensure that wind- and solar-generated electricity is still available even when the wind isn’t blowing or the sun isn’t out.

Yet as these super-sized batteries grow stronger and cheaper, regulators around the world are struggling to craft rules to ease them onto the grid. In the US, energy storage units have long been prevented from fully accessing the lucrative wholesale electricity markets where power plants sell electricity and utility companies buy it. Many state regulators view energy storage skeptically despite continued technological advances.

Based in the United Arab Emirates (UAE), Dr Imran Syed is head of industrial power for Enerwhere, designing and implementing hybrid systems that use energy storage. Dr Syed spoke to Andy Colthorpe about some recent project case studies.

Targeting customers with commercial and industrial (C&I) off-grid systems and using battery storage to greatly increase the share of solar they can use onsite, Dr Syed also talked about what challenges lie ahead both technically and business-wise, while also taking us through some of the big picture issues behind the dynamics of deploying energy storage in the Middle East.

“We play the ‘middle game’ – we’re not in the residential space and we’re not in the large grid-connected systems in the hundreds of megawatts,” Syed says of how his Enerwhere business unit is positioned.

“Let’s say anywhere between 500kW up to about 20MW – 30MW and maybe up to 50MW. The core of what we offer is off-grid systems: we go and find systems that are running on diesel generators that are off the grid and we replace those with hybrid systems.

“Historically it’s always been solar-diesel mostly – and there’s a limitation always to how much solar you can throw [in] when there’s a diesel generator because there’s nowhere for that solar to go and because the cost of solar has always been quite competitive when compared to the cost of producing power with diesel.

“That’s getting slightly worse considering the diesel prices right now, but it’s always been in general in a country that’s not subsidised or if you have taxes on diesel then solar against it always makes sense in terms of prices.”

While throwing in as much solar as possible is a good start, without storage, the upper limit of that possibility is constrained to around 20%-30% over a year of energy consumption at an off-grid site. Storage can store any excess solar, while also helping to stabilise the system and run it properly, minimising the use of the diesel generator if not yet eliminating the diesel altogether. A couple of years ago, Syed says, after exploring the possibilities around batteries, Enerwhere “stuck our necks out and bought a Tesla Powerpack system”.

Energy storage can provide immediate, tangible savings to ratepayers, and drive significant benefits to the electricity system and the economy as we recover from the COVID-19 crisis. But action needs to be taken now to realize these benefits.

Our recently released report, Unlocking Potential: An Economic Valuation of Energy Storage in Ontario, found that the introduction of just 1,000 megawatts of energy storage in the province could lead to net savings of more than $2B over the next decade. For residential electricity customers, that translates to between $4.50 and $11.50 in savings per year. Simply put, energy storage helps the power grid operate more efficiently, and helps electricity consumers shift how they use electricity – by storing low-cost, often surplus electricity (including from renewable wind and solar resources) during off-peak times to using it during times when electricity is in high demand, more expensive, and sometimes more carbon-intensive.

However, there’s currently an inability to fully integrate energy storage within Ontario’s electricity market. In order to unlock the system-wide value of energy storage now, Energy Storage Canada recommends for the Independent Electricity System Operator (IESO) in consultation with utilities and the Ontario Energy Board, to immediately procure energy storage resources to begin to realize savings identified in the report and to develop an enduring new market mechanism for energy storage in the medium and long term.

Fully enabling energy storage would not only provide the ratepayers savings identified in the report but as well as adding to Ontario’s GDP and creating jobs to the province and helping reduce GHG emissions. The jobs contribution of energy storage is significant and unique to this resource in part because of the diversity of assets that storage represents, ranging from commercially-facing jobs across the province for behind-the-meter assets to large-scale infrastructure projects that result in long-term job growth.

But in order to realize these benefits from fully enabling energy storage action needs to be taken now otherwise Ontario risks falling behind other jurisdictions who are taking concrete steps to unlock the potential of energy storage.

The prospects for a green COVID-19 recovery are getting better with every passing day in the EU, and it seems that the UK is not about to be left behind in the dust. Last week the UK government announced one simple rule change that will speed the construction of large scale energy storage facilities for wind and solar power in England and Wales. It’s just one rule, but the difference is significant because it expands the field of battery technologies to include liquid air and other bulk systems.

If all goes according to plan, the rule change will enable the UK to build more than 100 bulk, long duration energy storage systems in short order, tripling the number currently operating in England and Wales.

High capacity and long duration are essential for the sparkling green grid of the future, and that means new technologies must be shepherded on through. Today’s lithium-ion batteries perform well enough, but they only discharge for a few hours. Meanwhile, grid planners are asking for a full day, or even multiple days, in order to introduce more wind and solar.

Long duration battery technology already exists, but speeding up construction is the key factor considering the urgent need for swift action on climate change and the need to get people back to work on the heels of the COVID-19 outbreak.

In order to get that done, the UK government is lifting restrictions on large-scale batteries of more than 50 megawatts in England and 350 megawatts in Wales.

It wasn’t actually all that simple. The planning process involved months of stakeholder meetings and input beginning last October in addition to procedures in Parliament earlier this month, which amended the Planning Act of 2008 and the Electricity Act of 1989.

The end result is that local planning authorities will get to decide on bulk energy storage projects, instead of having blanket restrictions imposed under rules for Nationally Significant Infrastructure Projects in England and Wales.

Tesla’s energy storage business picked up steam in the second quarter and even played a minor role in the company’s fourth consecutive quarter of profitability, according to earnings reported Wednesday.

Commercial and residential energy storage sales as well as solar are still mere slices of Tesla’s overall business, which is largely dominated by automotive. However, second-quarter results show some promise for energy storage, particularly Megapack, the utility-scale energy storage product that launched in 2019 and is modeled after the giant battery system it deployed in South Australia.

While Tesla does provide separate deployment stats for solar and energy storage, it combines the two when reporting revenue, making it impossible to fully measure the success of Megapack. However, Tesla made a point in its earnings statement to flag Megapack as a winner in the second quarter, and noted that it turned a profit for the first time.

“There’s a lot of demand for the product and we’re growing the production rates as fast as we can,” Drew Baglino, senior vice president of powertrain and energy engineering, said during Wednesday’s earnings call.

For the past four years or so Tesla has been asking investors to view it as an energy company instead of just an automaker. Some analysts think that the real value in Tesla’s business will be when it actually achieves some level of parity between the two sides of the shop — a goal that Musk is also shooting for.

But energy storage and solar has remained in Tesla’s automotive shadow, despite assurances that these business products will eventually be equals. For now, energy storage remains a small, but growing, fraction of Tesla’s revenue.