NJBPU President Joseph L. Fiordaliso

The New Jersey Board of Public Utilities (NJBPU) has formerly accepted a report, entitled Grid Modernization Study: New Jersey Board of Public Utilities, which includes a full set of recommendations, and authorized the public release of the report. In recommending the board’s acceptance of the report, staff indicated that the report outlines a framework for modernizing the grid and its recommendations would significantly improve New Jersey’s interconnection rules.

The state’s grid modernization initiative included research into similar state programs and emerging technologies, organization and execution of a comprehensive series of stakeholder meetings, and data requests for specific information from New Jersey’s Electric Distribution Companies (EDCs), which all culminated in the report’s recommendations to modify certain interconnection standards. Modifying these standards will enable greater adoption of clean energy resources needed to meet New Jersey’s clean energy goals by improving how they are connected to the electric grid.

“This report and its recommendations are vital to the process of modernizing the grid so that our many new sources of clean energy like solar, as well as energy storage, can more easily connect now and into the future,” says NJBPU President Joseph L. Fiordaliso. “I would like to thank board staff and our consultant Guidehouse for their hard work on an extremely important topic, and to our stakeholder community who provided invaluable feedback throughout the process.”

Further, the board directed staff to release for public comment a draft of the proposed rule changes needed to implement recommendations 1 through 4 in the report that would modify the interconnection rules. These modifications would provide near-term relief from the issues that impede higher rates of interconnection approval for distributed energy resources (DER), such as solar and energy storage.

Staff has also been directed to initiate the analysis and stakeholder input process needed to kick start the rule making process for recommendations 5-9, which are longer term recommendations. These recommendations are generally more complex and will require additional analysis and stakeholder input prior to being incorporated into a second rulemaking proceeding. Some of these longer-term improvements may require legislative action.

The final report was developed by Guidehouse Inc., which developed the document through a robust public process, which included five stakeholder meetings over the last 12 months.

Near-term recommendations from the report include ensuring New Jersey is aligned with the latest grid interconnection standards of the Institute of Electrical and Electronics Engineers (IEEE). It recommends streamlining and automating the interconnection application process including an interconnection dispute resolution process. It also pushes to enhance hosting capacity methodology, hosting capacity and map data granularity, minimum update intervals, and presentation consistency. This would include the electric distribution companies (EDC) providing a uniform cost data guide for system upgrades.

The recommendations call for designing and implementing an EDC pre-application process in accordance with NJBPU requirements, which will provide the opportunity to expedite renewables and storage interconnection. The process should enable key information affecting project viability to be exchanged between the EDC and the customer prior to initiating a standard interconnection review.

Long-term recommendations from the report include NJBPU developing a steering committee and convene working groups and task forces to further reform the interconnection and grid modernization process. The steering committee should recommend tools and an approach for a “regulatory sandbox” to test for “fail or scale” of new technologies and processes.

Informed by a stakeholder process initiated by NJBPU, NJ EDCs should implement a streamlined flexible queue process across EDCs which would include a mechanism to prioritize a “first ready, first through” approach. This would support more viable projects and avoid clogging the queue for Level 1, Level 2 and Level 3 projects, while ensuring equity and fairness in the queue.

NJBPU should establish a steering committee and working groups to research and recommend additional cost recovery options beyond the legacy cost-causer approach. Alternatives, which comply with the concept of prudently incurred costs and do not systematically favor private, unregulated developers at ratepayers’ expense should be researched.

NJBPU should direct the EDCs to develop integrated distribution plans (IDP) per the NJ Energy Master Plan (NJEMP) and should provide direction to the EDCs regarding information to be included as minimum filing requirements in their IDP / IDER (integrated distributed energy resource) plans. NJBPU should provide a rulemaking that non-renewable fuel sources should be separately metered from renewable sources, and cannot be combined for net metering purposes. This will allow renewable generation owners to receive full credit without penalty for co-located non-renewable sources, and without sacrificing resource sufficiency.

Proposed rule changes for the recommendations will be submitted to the Office of Administrative Law (OAL) for publication in the New Jersey Register. The board will consider public comments received before adopting final rule changes and publishing them in the New Jersey Register.  The rule proposal for the near-term recommendations will be submitted to OAL after receiving public comment on the draft rule language. The rule proposal for the long-term recommendations will be developed following a robust stakeholder engagement process and submitted when the proposal is developed.

Continue reading

The Marine Corps Base (MCB) Camp Lejeune has awarded Duke Energy a $22 million utility energy service contract (UESC) for the design and construction of a microgrid at the military base. The microgrid solution includes upgraded electrical infrastructure; 5 MW of on-site natural gas-fired generation; a 5.4 MW battery energy storage system; integration of an existing solar photovoltaic system; and a microgrid controller to provide integrated demand management, black start and islanding capability.

“We’re excited to bring additional energy reliability and resiliency to Camp Lejeune,” says Melisa Johns, vice president of distributed energy solutions at Duke Energy. “This project offers a number of innovative and integrated solutions that will lead to more efficient energy use and significant cost savings to Camp Lejeune.”

The award leverages Energy Resilience Conservation Investment Program (ERCIP) funding to install the microgrid at Camp Johnson, an education and training area located within Camp Lejeune.

“The Marine Corps is investing in state-of-the-art infrastructure to position installations to prevent, recover and survive a prolonged loss of electrical service from weather – and climate-related events,” explains Marine Corps Installations Command Public Works Director Walter Ludwig. “This UESC award is a major step toward furthering the reliability, resilience and efficiency of Camp Lejeune’s electrical infrastructure and on-site generation capabilities.”

Located in Onslow County, N.C., Camp Lejeune is home to the largest concentration of Marines in the Marine Corps. It makes up nearly 20% of the Marine Corps’ installation energy consumption. In addition to multiple other energy efficiency projects, Duke Energy also completed a 13 MW solar facility at Camp Lejeune in 2015.

This UESC project is part of Duke Energy’s unregulated federal business as a Department of Energy certified Energy Services Company.

Continue reading

Batteries from Audi vehicles are used at this site in Germany, recently brought online by RWE. Image: RWE.

While battery storage growth in the US continues to vastly outpace that of Europe, the repurposing of used EV batteries into second life stationary storage systems is far more developed in the latter.

Europe has a handful of companies specialising in deploying used EV batteries into stationary battery energy storage systems (BESS), including Connected Energy (UK), Evyon (Norway), BatteryLoop (Sweden), Octave (Belgium), Tricera, encore and Stabl Energy (all Germany). Meanwhile, North America has just one – Canada-based Moment Energy.

That is partially because of more stringent requirements on automotive OEMs to find solutions for their EV batteries once they can no longer be used on the road, be it recycling, repurposing or re-using. In the US, responsibility for this falls on the end-user, Moment’s CEO Edward Chiang told Energy-Storage.news.

“Consumers can’t pay these insane costs for recycling. Governments are moving towards Europe’s approach. California is pushing hard on this and the federal government is too,” he said.

But the other, perhaps definitive reason is that for a second life BESS to be deployed in the US it needs to be built in a facility certified with UL 1974, a standard specifically for second life storage systems from the certification body. The only one in the world is in Japan, belonging to 4R Energy Corporation, a JV between Nissan and Sumitomo Corporation, which was certified in 2019.

Moment Energy is building a facility in British Columbia which will be the first in North America with the certification. “We’re working directly with UL on it so it’s just a matter of time,” Chiang said.

Energy-Storage.news’ publisher Solar Media will host the eighth annual Energy Storage Summit EU in London, 22-23 February 2023. This year it is moving to a larger venue, bringing together Europe’s leading investors, policymakers, developers, utilities, energy buyers and service providers all in one place. Visit the official site for more info.

After that comes the 5th Energy Storage Summit USA, 28-29 March 2023 in Austin, Texas. Featuring a packed programme of panels, presentations and fireside chats from industry leaders focusing on accelerating the market for energy storage across the country. For more information, go to the website.

Continue reading

Hugh McDermott

Michigan energy provider Consumers Energy has selected ESS Inc., a manufacturer of long-duration iron flow batteries for commercial and utility-scale energy storage applications, to provide a battery system for a solar and storage microgrid. Consumers Energy will deploy ESS’s Energy Warehouse platform as part of a microgrid powering a gas compression facility in Michigan.

The project, which includes the first iron flow battery to be used for a gas compression plant, underscores the capabilities of ESS’s Energy Warehouse to deliver low-cost, long-duration energy storage over a 20+ year operational lifespan. When paired with solar photovoltaics, the Energy Warehouse provides a sustainable, resilient energy storage solution for critical infrastructure.

“ESS is proud to provide our safe and non-toxic battery storage system to a leading utility provider in the Midwest serving millions of customers,” says Hugh McDermott, SVP of business development and sales at ESS Inc. “We are especially pleased to have our first project for Consumers Energy be a solar-plus-storage microgrid – a hugely beneficial solution for utilities and commercial/industrial customers who need sustainable and cost-effective energy resilience solutions.”

“Consumers Energy’s partnership with ESS on this first-of-its-kind project is another positive step toward a cleaner energy future for Michigan,” states Dennis Dobbs, VP of gas engineering and supply at Consumers Energy. “This project delivers on our goal of producing and storing clean, renewable electricity to help the environment, reduce electric bills and increase operational efficiency at the compressor station. And by integrating ESS’s Energy Warehouse, we are able to ensure the safe, dependable operation of our critical infrastructure.”

Continue reading

Sunrun and Ford have partnered to turn the new F150 electric truck into a vehicle-to-home energy storage system. Image: Sunrun / Ford.

We speak to Sunrun senior director of market development and policy, Chris Rauscher, in the final instalment of our series of energy storage industry leader interviews at RE+ 2022.

While much of the focus of our coverage here at Energy-Storage.news is on the larger, utility-scale end of the market, residential energy storage is also on the rise.

Wood Mackenzie Power & Renewables noted in September that although the grid-scale market dominates deployments in the US, accounting for 2.6GWh of a total 3GWh of Q2 2022 installations, it was the strongest quarter to date for residential in terms of megawatt-hours, with 375MWh.

By 2030, another analysis firm, BloombergNEF, predicts that a quarter of all energy storage deployments annually will be in the residential and commercial and industrial (C&I) segments.

As we heard in our recent interview with sonnen Inc CEO Blake Richetta, residential batteries can help the electricity network as well as individual users, through aggregation into virtual power plants (VPPs).

The same can be said for Sunrun. As a leading residential installer, the company has quietly become one of the biggest owners of solar PV assets in the US. Having begun attaching battery storage to solar installs, the company recently noted that during this summer’s California heatwaves, it dispatched more than 80MW of aggregated residential storage to the grid.

Similar moves have been made by Sunrun in ISO New England territory and the company was recently awarded a 17MW VPP contract in Puerto Rico.

Chris Rauscher joined Sunrun seven years ago after time spent as an energy policy advisor in the US Senate. Now working among the policy team there, Rauscher said his focus is mostly on new business lines.

We start our conversation asking about Sunrun’s recent tie-up with carmaker Ford. Ford’s new F-150 Lightning all-electric truck can be configured as a home backup source, using the truck’s battery and Sunrun’s home charger interface.

The partnership with Ford on the F-150 truck caught some attention a few months ago. Perhaps as a starting point you can tell us a little bit about that?

Chris Rauscher: It’s a project in two phases. [The first phase is] vehicle-to-home, in a backup situation, also called non-parallel operation. We’ve been installing that for a few months, and then in the future, possibly next year, we’ll add vehicle-to-grid (V2G) in a parallel operation scenario, but that all depends on getting the rules right with the utility, whether the utility has a programme where the utility can benefit, and the customers can benefit.

There’s been an unbelievably high level of interest from customers, utilities, regulators, and policymakers. It’s exciting to have that amount of capacity at the residential level. You’re talking for the long-range truck, 10 Tesla Powerwalls in terms of capacity, 130kWh.

That unlocks very exciting things that we can do with the vehicles, it doesn’t take many vehicles to have a real impact.

We’re speaking here in California where there’s a phaseout of internal combustion engine (ICE) car sales. Will things like V2G that can lower the cost of ownership of EVs, that customers will need to have anyway, be quite compelling?

I was presenting yesterday on this project, and somebody asked me if I could I give them an ROI on buying the truck. That’s a really interesting question, because there is no ROI on buying an internal combustion engine vehicle.

And when we’ve taken a look at grid service programmes, primarily Bring Your Own Device (BYOD) programmes, peak reduction programmes, the numbers start looking really compelling. Both from an individual customer standpoint, and then if you’re operating them as Sunrun, operating as a virtual power plant, or as a fleet, they look really, really compelling.

Sunrun: Not just a big residential solar company, a big solar company, period. Image: Sunrun.

Two pushbacks we hear about on vehicle-to-grid have been traditionally on the warranty side and then also on the customer side. On the customer side, people might be reluctant to hand the utility control of their car’s battery. Is it about building a compelling economic case so that customers are happy to enrol? 

It’s a good point, it actually holds true for stationary battery customers as well. Years ago, we did early customer surveys. Customers did not want to share their batteries with the utility. One of the reasons they were getting solar and battery storage is because they don’t like what they were getting from the utility.

Once you start reframing it as sharing with your neighbour, and helping to reduce everyone’s costs on the grid, that paradigm really shifts quite a bit. Putting aside the environmental considerations, if you’re getting a cheque for some infrastructure that you already have in your home, or vehicle that you’re paying a monthly lease on, that really shifts people’s thinking.

The scale of the resource here, it’s 130kWh for a long-range truck. You have power for many, many days if the grid goes out and then if you have solar, you have power indefinitely because you can recharge the batteries. Then looking at normal operation for peak events, it was 2,000MW of demand response and DERs that saved the California grid a couple of weeks ago during the crisis.

We’ve done the modelling that shows that’s only 200,000 F150 Lightnings that could have provided that. It sounds like a lot, but Ford sold 125,000 internal combustion F150s last year in Texas alone. They sold around 850,000 nationwide, so it’s really not that many trucks that would have been able to keep the California grid up, and those trucks could have done that for 13 hours.

At Energy-Storage.news, a lot of our focus is on the utility-scale end of the market. However, as the installed base of residential battery storage grows, it’s fascinating to see the different ways initiatives, technologies and business models come together to scale up the benefits and capabilities batteries and other distributed energy resources (DERs) can bring. Is the recognition of the value of home batteries growing in the US beyond behind-the-meter applications like backup power and solar self-consumption?

People think of us as a ‘big company for residential’. We’re actually either the second or third largest owner of solar assets in the United States. At any scale, only NextEra is bigger than us. That’s mind boggling.

Increasingly, what we are seeing, and California is a proof point here, utilities and policymakers coming to us saying, “We’re now seeing your scale. How can you help us? Can you dispatch your batteries? Can we partner with you?”

That’s very different from a couple of years ago where we were just doing a lot of pilots, announcing a lot of virtual power plant deals of different structures around the country, trying to get some traction.

I think increasingly, it’s really going to be shifting as we deploy bi-directional EVs, where utilities and market operators come to us and say, “Hey, you have megawatt-scale here, if gigawatt-scale around the country, how can we partner?”

The recent heatwaves in California proved energy storage – including residential and C&I – is an important grid resource, or that it can be if given the opportunity. How then to build scale with replicable models?

That performance was really important for the grid, obviously, and for our customers, and it’s just a really solid proof point that we can be there in times of crisis and can be there.

We were really happy to partner with CAISO and the utilities on that and provide that peak reduction. That’s something that should be called on more regularly, and not just in times of crisis but every day of the week when we when we hit peaks.

Under CAISO’s Emergency Load Reduction programme, the battery units only dispatch to the grid when electricity shortfall triggers ‘Flex Alerts’. What needs to happen for them to be a daily peaking resource?

What we’re seeing in California is there are a lot of different DER programmes run by lots of different stakeholders, and sometimes for different technologies. They have different dispatch protocols, different cycles, and schedules and different payment structures, and different counterparties.

We need to take the friction out of the system and streamline in California and have more unified programmes. I would point to Massachusetts that’s really done this very well, they have the Connected Solutions Bring Your Own Device programme.

At every single utility, it’s called the same thing and the payment is known, well ahead of time, it’s a per kilowatt-season payment, the pricing is known well ahead of time, and the dispatch schedule is known well ahead of time.

You can place any qualifying device in the programme: a thermostat, a battery, it could be a single, uni-directional EV.

It tracks the ISO New England wholesale market peaks, and the utility is trying to reduce their share of the wholesale market peaks. When they reduce their share, they achieve cost savings for the customers. They pay us for performing and the rest of the saving goes to the customers.

We really need to see this type of streamlining in California, and a replication of this northeast BYOD programme everywhere in the country.

The other thing that Connection Solutions gets right is that it’s metered at the battery’s inverter or the performing device, not metered at the utility point of connection.

That’s really important because it means that you’re receiving credit for any power that you push out of the battery during that peak event. Whether that power goes to the home or to your neighbour’s house is irrelevant.

Finally, everybody at RE+ 2022, the US’ biggest solar PV and energy storage trade show, is talking about the Inflation Reduction Act (IRA) and their optimism for the boost it will bring an already fast-growing pair of industries. What’s your view on the IRA, and what’s Sunrun’s view?

I was initially hired seven years ago to work on extending the [solar] investment tax credit (ITC) in 2015 and we got it done. We’ve done it another couple of times since then and it’s always very expensive and takes a lot of effort and resources.

To not have to do that for the next decade, it’s amazing to have that certainty and to not have to safe harbour equipment as we would in the past when coming up on an ITC cliff.

This is going to give us at the federal level, not in trade or other issues, but at least on this question, the certainty that we really needed to be able to ramp and grow the business on an accelerated pace.

In terms of what the standalone ITC for batteries will do, I don’t think that we have a specific view on that but obviously, it’s really going to change the use case for residential batteries if you can charge from the grid. I think we’re going to see a lot of really exciting ways of getting much more value out of each individual battery, but for Sunrun I can’t say anything specific yet.

The IRA also has lots of incentives and programmes for whole home electrification and you’re seeing Sunrun – the partnership with Ford is the first foray into this – but you’re seeing us become an electrification company, as well as a solar and battery company.

For so long, we’ve been seen as competitors of utilities, but really now, as an electrification company, we are agents of load growth. So, if we install a bi-directional charger, for a long-range Ford F150, on an average home, their load over the year, their consumption might go up by 50%, or it might double, depending on how much electrification they already have in the home.

For the average house in the US, we can’t put enough solar on the roof to fully offset all of that new demand, which means we feed the home with solar to the greatest extent possible and then the customer is still buying tonnes of electricity from the utility.

We want to partner with utilities, we want their eyes to be open to this opportunity, where even after we put solar everywhere, there’s still plenty of kilowatt-hours to go around. It’s good for the climate, obviously, because you’re taking all of those dollars that would have gone to fossil fuels, putting them onto electricity, and then we do our best to clean up the supply.

Our game plan for combating climate change does not need to be more complicated than that. Electrify everything and run it on clean energy.

Energy-Storage.news’ publisher Solar Media will host the 5th Energy Storage Summit USA, 28-29 March 2023 in Austin, Texas. Featuring a packed programme of panels, presentations and fireside chats from industry leaders focusing on accelerating the market for energy storage across the country. For more information, go to the website.

Continue reading

Polar Night Energy’s sand-based thermal storage system in Finland, which made headlines globally when it launched in summer. Image: Polar Night Energy.

With nearly half of global emissions coming from heat processes, clean long duration energy storage (LDES) which can store thermal energy are crucial for decarbonisation, says a new LDES Council report.

Thermal energy storage solutions can decarbonise heat applications by electrifying them, firm heat with variable energy resources and optimise heat production in industrial processes.

A new report by the Long Duration Energy Storage (LDES) Council says that thermal energy storage, or TES, has the potential to expand the overall installed capacity potential of LDES by to 2-8TW by 2040, versus 1-3TW without. This equates to a cumulative investment of US$1.6-2.5 trillion, and would result in system savings of up to US$540 billion a year.

Use cases include storing and utilising electricity from renewables, storing and utilising heat generated from industrial processes or from heat-based renewable generation, as well as drawing in and storing clean energy from the market.

TES comprises a range of technologies ranging from freezing to 2,400°C storage temperature, for hours to months of duration. The report claims that solutions have an internal rate of return (IRR) of 6-28% for chemical plants, 22% for ‘off-grid greenhouse’, 0-16% for district heating peaker plants and 16% for alumina refineries.

The capex requirements for discharging equipment – i.e. power capex – of TES are expected to fall by 2040, by 15-30% for steam-based applications and 5% for air-based ones. These are based on figures provided by LDES Council members. Members that provide TES solutions include 1414 Energy, Brenmiller Energy, EnergyNest, Malta Inc and MGA Thermal.

Energy storage capex requirements are expected to fall even further, by 25-70% by 2040 depending on the type of heat.

While not a member of the Council, Polar Night Energy’s ‘sand’ battery in Finland made headlines around the world when it went online in summer this year. Read Energy-Storage.news’ coverage of that project here.

Market design changes that could incentivise more deployments include carbon pricing, variable electricity pricing and payments for flexibility provision, the LDES Council said.

The report, which you can download here, gave some business case examples of TES in action. One business case was the generation of medium-pressure steam in a chemicals plant, using an electric boiler with TES. Alongside steam generation, use cases include drying, humidification, cleaning, moisturisation, sterilisation and disinfection and process heating, and the project has a potential IRR of 28%.

Another was replacing a 250MW peaker gas boiler for district heating with a TES powered by offshore wind, which could result in a 16% IRR.

See previous articles by Energy-Storage.news on the topic of thermal energy storage here.

Continue reading

SemperPower turned its first utility-scale energy storage system on this time last year. Image: SemperPower.

Construction has started on a 30MW/63MWh battery energy storage system (BESS) in the Netherlands from Rolls-Royce, which will be the largest in the country when complete.

Developer SemperPower has launched the start of construction for Project Castor, a 2.1 hour-duration system at an energy hub of the North Sea Port in Vlissingen-Oost in the southeast of the country. The system will come online in the spring of 2023.

Aerospace and defence company Rolls-Royce is providing the BESS under an engineering, procurement and construction (EPC) agreement. The system will support the integration of new renewable energy resources into the Dutch grid. A press release was not more specific, but this could be done by alleviating the intermittency of wind and solar as well as providing frequency response services.

SemperPower commissioned its first utility-scale energy storage system 12 months ago when it turned on a 10MW system in Terneuzen, Netherlands (pictured).

Rolls-Royce has been delivering BESS solutions for several years now through its Power Systems division. In 2020, Energy-Storage.news reported on projects the company was delivering in Costa Rica and Rarotonga in the South Pacific, but the new project in the Netherlands is substantially larger.

It eclipses the size of GIGA Buffalo, the largest operational system in the country today at 24MW/48MWh, which came online in October.

Andreas Görtz, President Sustainable Power Solutions, Rolls-Royce Power Systems, said: “With our new utility-scale battery storage systems that support the integration of renewable energy sources into the power supply, we are taking another step with our customers towards net-zero greenhouse gas emissions. We are very much looking forward to working with SemperPower on Project Castor.”

The Netherlands has a particularly congested grid, being one of the most densely populated countries in Europe, so some local regions have reached limits for the feed-in of new wind and solar. To get around this, some battery storage operators are exploring time-limited contracts with grid operators where they can only charge or discharge at certain periods to alleviate grid strain.

Triodos Bank and The Dutch National Fund for Green Investments are providing the project financing.

Emile Peters, investment manager for The Dutch National Fund for Green Investments, added: “Energy storage systems for renewable energy are relatively new. Consequently, it is challenging for financiers to properly assess the associated risks, generally resulting in avoiding financing such projects altogether.”

“The Dutch National Fund of Green Investments, in this case together with Triodos, aims to finance sustainable pioneers like SemperPower, so that they can focus on accelerating the energy transition.”

Continue reading

AGL’s 53MW solar PV plant at Broken Hill. Image: AGL Energy.

Construction has begun on a large-scale battery storage project which will demonstrate advanced inverter technology, in the historic mining region of Broken Hill, New South Wales, Australia.

Major Australian energy generator-retailer AGL announced this morning that it has broken ground on the 50MW/50MWh battery energy storage system (BESS), aiming to have it operational by mid-2023.

Broken Hill has a long history as a mining city, which brought industry to the area in the mid-20th Century as silver ore was discovered. More recently, the area has become home to solar PV and wind installations, including AGL’s 53MW Broken Hill PV plant which went online in 2016 and its 200MW Silverton wind farm which went online a year later.

However, Broken Hill only has a weak connection to the grid and locally generated renewable energy is often curtailed at times of surplus. The site was chosen as an ideal location to test out the capabilities of smart inverters to help balance the local electricity network.

As reported by Energy-Storage.news in March, the AU$41 million (US$26.32 million) project is being supported by the Australian Renewable Energy Agency (ARENA) with AU$14.83 million of its cost. AGL’s BESS project will demonstrate and test how advanced inverters can provide inertia to the electricity network, a role traditionally performed by the rotating mass of thermal power generators.

“As Australia’s electricity system switches to higher rates of renewables it will be increasingly important to deliver storage solutions that have the capabilities to stabilise the grid,” ARENA CEO Darren Miller said at an event yesterday to mark the start of the project’s construction phase.

“AGL’s Broken Hill Battery allows us to test advanced inverter technology in some of the most challenging conditions for the grid, while also improving system security and stability in the region.”

Technology provider and system integrator Fluence has been contracted to supply the Broken Hill BESS. The company said the battery system will be permanently set to grid-forming mode, resisting changes in network voltage and frequency, and providing synthetic inertia through the ‘Virtual Machine Mode’ in the Fluence software and controls system.

Wave of advanced inverter projects

The ARENA demonstration project concludes in July 2025. It aims to accelerate commercialisation of large-scale BESS with grid-forming inverters in weak-grid areas, provide cheaper alternatives to expensive grid infrastructure equipment like synchronous condensers, help de-risk renewable energy investment, inform stakeholders like network operators and utilities of the capabilities of smart inverters.

The project will also be used to assess whether there needs to be standardisation of equipment and protocols for grid-forming battery systems.

This is important because Broken Hill is one of just many battery storage projects that are being fitted out with advanced inverters. Some existing large-scale BESS assets, like the Hornsdale Power Reserve in South Australia, have been retrofitted with them.

At the same time, ARENA is offering funding for other new advanced inverter BESS projects and earlier this year launched a competitive solicitation.

In September, the state government of Victoria announced AU$126 million funding for two grid-forming battery storage projects.

In addition to its grid-forming duties, the Broken Hill BESS will also play into opportunities in the National Electricity Market (NEM) for applications like frequency control ancillary services (FCAS) and wholesale arbitrage.

The BESS could be joined in Broken Hill in a few years by a much larger system using a very different technology. Canadian company Hydrostor is developing a 200MW/1,600MWh advanced compressed air energy storage (A-CAES) plant in the region.

Last month ARENA committed AU$45 million towards the cost of Hydrostor’s Silver City project. It has already been chosen by New South Wales transmission network operator Transgrid as its preferred option to provide backup power supply to the city of Broken Hill. Hydrostor hopes to achieve financial close on the project next year.

Meanwhile for AGL, Broken Hill is the latest in an energy storage portfolio buildout that looks likely to include a couple of multi-gigawatt-hour battery systems at former coal power plant sites.

Continue reading

It is Ingeteam’s first major project in Australia. Image: Ingeteam.

Spain-based energy conversion equipment specialist Ingeteam has commissioned a 10MW/20MWh battery energy storage system at a wind farm in Australia.

Utility Naturgy selected Ingeteam for the project which has seen the latter supply the battery containers, power conversion systems, control system, and assemble, commission and then operate the BESS unit.

The contract to Ingeteam was awarded by Global Power Generation (GPG), which is 75% owned by Naturgy with the Kuwait investment Authority holding the remaining 25%.

The BESS is ‘associated’ with the 109M Berrybank 2 wind farm the state of Victoria, which GPG will begin operating in the coming months, a press release said.

However, the BESS itself is located in the Australian Capital Territory (ACT) within the neighbouring state of New South Wales, and will support the ACT distribution network of the Queanbeyan substation.

“This project has been a real challenge for us, since it involved an integral supply (power stations, battery containers, control system, etc.) for a project developed in the antipodes and everything this in a very complicated context due to the numerous restrictions posed by the pandemic,” said José Antonio Unanue, director of Ingeteam’s BESS division.

“It would not have been possible to successfully complete this project if we had not had the fundamental contribution of our subsidiary in Australia. That is why from the BESS business we are very satisfied and proud to have carried it out successfully.”

The company supplied four 2.5MW/5MWh battery enclosures and two of its all-in-on power conversion systems (with inverters, transformers, medium voltage cells and more).

Ingeteam, whose head office is near Bilbao, has deployed systems for numerous co-located projects in the last few years. In 2020, it supplied a 50MWh system at a large wind farm in Scotland while in 2022 it has deployed units at green hydrogen and solar-plus-storage projects, both on home soil.

Continue reading

Manish Nayar

OYA Renewables, an energy transition solutions platform, and energy company Oil Well Shares (OWS) have formed Chrysalis Energy, a joint venture (JV) to develop and construct community and utility-scale solar, wind and energy storage infrastructure projects across the PJM region. The partnership allows for the development, construction and operation of over 3 GW of renewable energy assets across 1.5 million acres of mainly contiguous, rights-owned land within Pennsylvania, Ohio and West Virginia.

The initial phase of development – which is anticipated to be completed by 2030 – is expected to be followed by ongoing energy transition infrastructure development within the region which the JV accommodates in perpetuity.

“It would be difficult to overstate the impact that this joint venture will have on the economic prosperity of this region and the national transition to clean energy,” says Manish Nayar, chairman and founder of OYA Renewables. “The sheer magnitude of the land position is remarkable, likely the single largest private land inventory in PJM and comprising 1/1000th of the entire continental U.S. acreage. Proximity to the Great Lakes is also highly significant, allowing us to explore green hydrogen opportunities in addition to solar, storage, and wind. We’re very proud to partner with an energy innovator like OWS. Its boots-on-the-ground local presence will be invaluable as we move to assess and develop renewable energy at scale.”

Within the scope of the JV, OYA and OWS will develop, construct, jointly own and operate an extensive portfolio of renewable energy assets across OWS’s current land inventory. The energy transition infrastructural development is projected to result in over $3 billion of capital being deployed in the PJM region by the end of the decade.

“As a third-generation energy company committed to investing in the communities where we live and work, we are excited to partner with a premiere renewables leader like OYA in providing reliable, economic and sustainable energy solutions for local businesses and communities,” adds Sid Sinha, CFO of OWS. “This unique JV is the right solution at the right time to address Appalachia’s current and future energy needs, with the key components and heft to deliver a sustainable solution at scale.”

Continue reading