Along with its fellow IOUs, Southern California Edison (SoCal Edison) and San Diego Gas & Electric (SDG&E), PG&E’s adoption of battery energy storage system (BESS) technology has been a major driver for California’s leading position among US states as an energy storage market over the past few years.
Long-time readers of Energy-Storage.news over the past 10 years will recall that as California’s AB2514 legislation put in place a mandate for the IOUs to procure 1.325GW of energy storage between them by 2020, an outsized portion of our reporting was driven by activity in the California Independent System Operator (CAISO) bulk power system.
That policy target took a while from its passing in 2010 into an actionable plan in the latter part of the decade but was quickly overshot as the needs of the CAISO grid converged with the falling costs of batteries.
Today, CAISO has more than 10GW of storage resources connected to it, and while other states are starting to catch up, most notably Texas with the Electric Reliability Council of Texas (ERCOT) service area, California remains a focal point for the US utility-scale BESS market.
Quick history
Over the past five years since deployment began at scale, PG&E has brought online more than 2,300MW of energy storage resources. More than a gigawatt will be added to that over the next year and a half to the end of 2025, PG&E’s Paul Doherty says, of a total 4.2GW of storage under contract.
“You can really see how these systems have proliferated and how state policy has really directed that in support of grid resiliency, the shift to renewables and the capability to load shift and buffer our energy for the evening peaks,” Doherty says.
Nearly all of the BESS resources in PG&E’s service area are third party-owned. PG&E has just one large-scale BESS in its ownership, the 182.5MW/730MWh Elkhorn project at the site of the former Moss Landing gas power plant, not to be confused with the slightly more famous 3GWh Moss Landing Energy Storage Facility at the same site owned by Vistra Energy with PG&E as its offtaker.     
Doherty points out that energy storage has been a “major” part of the utility’s resource mix since 1984 when its 1,212MW Helms pumped hydro energy storage (PHES) plant opened.
“We started to deploy actual battery energy storage systems in around 2012-2013 with a technology that was sodium-sulfur,” Doherty says.
That would be the sodium-sulfur (NAS) battery technology from Japan’s NGK Insulators. Two projects, one 2MW and the other 4MW, were deployed at a customer site and a substation through a customer-funded R&D programme called Electric Program Investment Charge (EPIC).
“Then in 2016, PG&E deployed our first lithium-ion energy storage system—that was Tesla Powerpack technology—at a substation about 50 miles north of Sacramento, to test out some real-world use cases.”
Those included testing the integration of BESS into the utility’s distribution grid system and how it could participate in CAISO markets. The company’s next trial project assessed how battery storage could be used to help manage peak summer loads on the PG&E network.
A project currently underway in mountainous Humboldt County attests to the direct way those trials translated into broader deployments.
One of the longest distribution lines in PG&E’s service area runs through Humboldt. By deploying a large-scale BESS to solve capacity and voltage issues, the utility is saving millions of dollars versus a traditional poles and wires upgrade.
Doherty calls it a “US$10 million solution versus a US$100 million solution,” along the 50-mile distribution line.
Wildfires and resiliency
California is among the US states with the most ambitious decarbonisation policy targets, aiming to reduce emissions to 40% below 1990 levels by 2030 and net zero by 2045. That’s a major driver for renewable energy deployment and, therefore, energy storage.
Improving the resiliency of electricity supplies, and the stability of the grid is also a major concern for utilities and the regulatory California Public Utilities Commission (CPUC) that oversees them.
The project in Humboldt County also speaks to that driver for PG&E to make investments in battery storage.   
California’s vicious wildfires imperil lives, and they imperil the electricity grid, and in the past, these threats have become intertwined with tragic consequences.
PG&E has been found liable for historic wildfires that started because the utility did not take sufficient measures to mitigate the risk of its equipment causing or exacerbating fire events.
Most recently, the CPUC approved a US$45 million settlement between PG&E and the regulator’s Safety and Enforcement Division (SED) in January this year, for the utility’s involvement in the 2021 Dixie fire, which burned across nearly a million acres before it could be contained.
Due to wildfires, the three IOUs now enact Public Safety Power Shutoff (PSPS) events in high-risk areas. These events essentially cut off power by de-energising distribution lines. They can last an indeterminate period of several days or even weeks.
In some of these areas, PG&E has built around a dozen ‘pre-installed interconnection hubs,’ essentially distribution-level microgrids, in downtown areas that are safe to energise, “even though the broader grid surrounding them is within the high-fire-risk areas,” Doherty says.
“We can bring in diesel generators and provide power to an area where there are community resources, like banks and gas stations and grocery stores, emergency services or other essential downtown places where people could go and still have that continuity of society where the rest of the town have their power shut down.”
PG&E is exploring greening those microgrids, trialling battery storage alongside mainspring linear generators that run on different types of gas.
It is also, with gravity energy storage startup-turned BESS integrator Energy Vault, building a large-scale system that combines lithium-ion (Li-ion) batteries with a green hydrogen electrolyser.
At 290MWh capacity, it will be a long-duration energy storage (LDES) system capable of powering the downtown and surrounding area of Calistoga for up to 48 hours during a PSPS event. The system is due to come online before the end of this year.

Hydrogen tank on its way to the PG&E-Energy Vault Calistoga microgrid project. Image: Energy Vault.
Incidentally, on the subject of new technologies, PG&E is also among the US utilities set to pilot the iron-air battery developed by Form Energy. The tech startup claims it will provide multiple days of low-cost electricity storage. Form is leading that project, Doherty says, with CEC grant funding.
“As a part of our continued integration of additional renewable resources, and maintaining resilience to the grid, we are piloting and testing the use of cleaner generation solutions for battery storage and for our microgrid sites,” he says.
“We’re really expanding the pool of our contracted technologies, piloting those viable non-diesel technologies in particular, and exploring opportunities to build a portfolio of non-fossil solutions for the longer term.”
Addressing ‘so many different grid focus areas and issues’ with energy storage
The utility therefore is procuring different scales and configurations of energy storage assets across its portfolio.
In addition to large-scale systems that operate in the CAISO market and help the utility meet its resource adequacy (RA) requirements and its microgrids, Doherty claims PG&E is also taking seriously the potential of customer-sited storage resources.
Energy storage is enabling the utility to “address so many different grid focus areas and issues,” including residential and commercial systems which can participate in demand response programmes, Doherty says.
“Californians have for a long time been early adopters of clean energy technologies, whether it’s EVs, whether it’s batteries or solar.”
Leveraging vehicle-to-grid (V2G) technologies from EVs equipped with bidirectional charging capabilities is “such an opportunity,” with PG&E expecting to support charging for three million EVs by 2030.
“We’re at more than 600,000 EVs connected to our grid today. That’s a really outsized number compared to the rest of the country and other utilities. We envision a future where two million of those three million EVs are participating in some sort of managed charging, or some sort of vehicle-to-grid applications.”
More broadly speaking, there are virtual power plant (VPP) programmes with Tesla and Sunrun that see home battery storage systems aggregated to provide demand response through PG&E’s Emergency Load Relief Program (ELRP).
It is still early days for VPPs, not least of all because ELRP only allows for batteries to perform demand response applications during peaks which occur during heat waves, but nonetheless they have been a huge success.
There is a “huge ecosystem” of battery storage applications across California, as Doherty says. Nowhere is this more evident than on the CAISO website, which features a portal where you can see how much energy storage is contributing to the ISO’s resource mix.
“It’s an exciting moment when you think about all that, and you think about the different grid architectures and the capabilities for batteries to support both on the utility-scale, but also the customer scale,” Paul Doherty says.

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Firm Power, a BESS developer, has 21 grid-scale projects currently in development across Australia, comprising 2.3GW of capacity in New South Wales, 2.7GW in Queensland, 500MW in Western Australia and 300MW in Victoria and South Australia, all in all totalling 5.8GW.
Terrain Solar, a large-scale solar PV developer, has six projects in development with a cumulative capacity of 1.8GW. Of this figure, 1.1GW is based in Queensland, 500MW in New South Wales, 100MW in Western Australia, and under 100MW in South Australia.
The acquisition will be completed in an A$250 million (US$165.5 million) deal, funded from cash on AGL’s balance sheet. The deal is subject to customary conditions precedent, with completion anticipated in 2024.
Managing director and CEO of AGL Energy, Damien Nicks, said the acquisitions will accelerate the company’s development pipeline, which recently hit 6.2GW of capacity. It will also ensure the company is “best placed to take advantage of market conditions and prioritise developments that generate the best long-term value and be a leader in the energy transition”.
“AGL’s development pipeline includes several mid-sized BESS projects, ranging between 200-500MW and two-to-eight-hours [of] storage duration. We believe this high-quality development pipeline presents strong optionality for AGL, focusing on firming capacity, which will be required to firm new renewable energy generation for our customer base and portfolio as thermal baseload generation exits the National Electricity Market (NEM),” Nicks said.
This article first appeared on our sister site PV Tech.

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The government is increasing the threshold for what constitutes a National Significant Infrastructure Project (NSIP) for solar and onshore wind to 100MW and 150MW, respectively, from 50MW currently.
“Now, the UK battery storage sector stands on the cusp of a transformative era, fuelled by the Labour government’s ambitious commitment to establishing the nation as a clean energy superpower by 2030,” Brooks said, as his company unveiled a 40-project pipeline.
Brooks also called for more to be done within planning reform, as well as the electricity market, to provide specific support for the deployment of BESS technology, which he said still faces several barriers.
Read Brooks’ guest blog in full here.

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The deal is significantly different to Gresham House and Octopus Energy’s recent shorter, two-year toll deal for a 568MW portfolio of 14 already-operational BESS projects. That was the first seen in the UK, while tolling agreements are common in the US and Australia.
In response to questions from Energy-Storage.news, BW ESS’s Roberto Jimenez, executive director for BW ESS, indicated that the seven-year BESS toll entails a fixed price for the entirety of it (presumably inflation-adjusted). He wouldn’t disclose how the figure was arrived at, considering the volatility of BESS revenues in the last three years, which makes seven years a very long time to agree a price on.
Jimenez pointed out that tolls are common in other infrastructure and related classes like solar and wind and said the deal is really about optimising the project’s financing. The project is also longer in duration—at 3.3 hours—than most other UK projects being built, and this played into the deal.
“Bramley agreed on a seven-year tenor because it optimised the project’s economic returns and is a tenor that is conducive for attractive long-term financing,” he said.
“The 3.3-hour duration of the Bramley BESS asset makes it attractive to traders/optimisers that expect to capture more value from arbitrages in the wholesale energy market. The choice of duration was also driven by technical considerations and a 15-year capacity market contract for 2.5 hours duration, which was secured for the project earlier this year.”
“There seems to be an increasing preference for longer duration assets, especially for longer-term deals, where assets need to be resilient in an evolving market.”
Market intelligence provider Modo Energy estimated in an analysis article that the toll price is most likely in the range of £70,000-80,000 (US$90,000-102,000) per MW. This was based on an estimated capex for the Bramley BESS project of £900,000 per MW and the revenues needed to achieve an unlevered IRR of 10% over the project’s lifetime (£108,000 per MW), balanced with the likely ‘spread’ or profit that Shell would want to make on trading the BESS.
Wider move to BESS toll deals could leave smaller optimisers at a disadvantage
Deals like Gresham House’s and BW ESS’ are part of a wider move in the UK and European industry to structures that enable financing for the largest-scale projects.
BW ESS said that tolls will be one of various structures that asset owners will go for, but that uncontracted merchant models and hybrid structures which leave some merchant exposure will have a place.
He indicated that for its two other large UK projects, Hams Hall at 400MW and Berkswell at 200MW, the company may retain some merchant exposure with those projects still uncontracted. Both are expected to come online in 2026.
Energy-Storage.news then asked Jimenez if there was room for smaller optimisation providers to provide tolls or whether it would be dominated by big utilities and energy companies, as the two large announced deals have been (Octopus and Shell).
“Optimisers could also offer toll agreements, but those may be perceived as less attractive as they do not provide the same ability to optimise a project’s cost of capital,” he said.
Others speaking off-record have put it more bluntly. A finance source recently said during a panel discussion that the best-performing BESS optimisers tend to be small, startup-type outfits that outperform large utilities and energy companies.
But asset-owners that contract with those larger entities are ‘effectively renting their balance sheet’ to get financing, they said. In other words, banks will be more willing to lend to a project optimised by a big entity with a deep balance sheet, even if its record of BESS returns is worse, because of the lower risk compared to an asset-light startup. The longer the length of the agreement, the more the risk element will come into the equation.

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The project is being developed by Terra Solar Philippines, Inc. (TSPI), which is co-owned by independent power producer (IPP) SP New Energy Corporation (SPNEC) and utility Manila Electric Company (Meralco). The green lane certificate was received by Emmanuel Rubio, president and CEO of Meralco subsidiary MGen.
Terra Solar would span 3,500 hectares of land in the Bulacan and Nueva Ecija provinces and would cost PHP185 billion (US$3.2 billion). The project would be the largest in the world by capacity, in terms of solar, BESS and both technologies combined.
The BOI is the Philippines government’s lead industry development and investment promotion agency and a green lane certificate is designed to speed up the process of acquiring permits and licenses for strategic investments that align with the country’s national development plans.
It is hoped the certificate could help Terra Solar reach commercial operations for its first phase—for which the size has not been disclosed—by February 2026 and the second phase the year after.
The project has also received a Certificate of Energy Project of National Significance from the Department of Energy, more of a formality as any project above US$59 million in investment value receives this certificate automatically.
The Terra Solar project appears to be the same one that was proposed by billionaire Enrique K Razon’s Prime Infrastructure Holdings two years ago, covered by Energy-Storage.news at the time. Prima Infra along with IPP Solar Philippines set up a joint venture entity called Terra Solar to develop the project. At the time, it was said the project would provide power to Meralco under a power purchase agreement (PPA) rather than being directly owned by the company, which appears to have changed.
The Philippines was a hot topic of discussion at Solar Media’s Energy Storage Summit Asia 2024 last month—see our write-up of one of its panels discussing the country’s energy storage market here (Premium access).
The BOI’s green lane certificate for Terra Solar coincided with several other renewable investment approvals from the department, including PHP263 million worth of solar rooftop projects, the PHP297 billion Pakil Pumped Storage Hydroelectric Power Project and the PHP114.7 billion Guimaras Strait Offshore Wind Power Projects.

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The majority of the projects are at ‘advanced stages’ of development and the first are expected to reach ready-to-build (RTB) status in the first half of 2025. The power and capacity imply an average duration of around four hours per project.
It builds on SUSI and BIWO’s partnership in Chile, with SUSI investing in two solar-plus-storage projects developed by BIWO in November last year, which will feature 232MWp of solar PV and up to 900MWh of energy storage capacity.
Energy-Storage.news has asked SUSI to confirm whether the new portfolio includes or is in addition to these and will update this article if an answer is received. The announcement implied, though didn’t explicitly say, that the 860MW portfolio is made up of standalone projects, implying they may all be new projects.
The energy storage market in Chile is being driven by its high – and growing – penetration of solar PV and the grid congestion that comes with that, considering the most regions with the highest irradiance are in the north while demand centres are in the south.
BESS are either being deployed as independent projects that help the grid operator manage congestion, trade energy and provide capacity market services, or alongside solar PV to support renewable power purchase agreements (PPAs).
Standalone energy storage’s participation in the electricity market was enabled in late 2022 while its capacity market payments were recently finalised too, paving the way for project owners to build a business case.
SUSI is also active in the energy storage markets in the US, with projects in ERCOT, and Italy.

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The project has a power output of 5MW and an energy storage capacity of 10MWh and can be operated at up to 20% overload for short periods. The 4,400 modules are divided into four BESS containers, pictured above.
The four BESS strings are each connected to an inverter and a medium-voltage transformer, and the entire project has a useful life of over ten years. The BESS is partly powered by the plants solar array which totals 9.4MW, and has numerous use cases.
Alwin Schmid, head of electrical engineering at Porsche, said the project was both about the environmental aspect of reusing batteries but also ‘stacking’ revenues and use cases of the BESS in an innovative way.
“Of course, this is about environmental aspects and the core issue of the energy supply. But it was also important to us to take a pioneering role with the storage system.”
“In this unprecedented model project, we were able to combine a number of different goals, including peak load capping, optimisation of self-consumption and simultaneous participation in the energy market.” 
It will be fully integrated into the energy market ‘in very marketable form’ by the end of the year, Porsche added.
The company want to make the Leipzig plant more economical and increase its self-sufficiency, said Jonathan Dietrich, overall project manager for battery storage at Porsche.
“We hope to gain insights from the project in order to be able to equip other Porsche locations with similar systems and capabilities in the future. At the same time, we can utilise batteries from test cars that are no longer suitable for demanding use in the vehicle for a second useful deployment before their final recycling,” he said.
Project is one of the larger second life BESS around
The project is one of the larger BESS projects around deployed using repurposed EV batteries. The largest Energy-Storage.news is aware of are 12MWh and 28MWh systems in California, both deployed by firm B2U.
In Germany, three totalling 25MWh will be built by ABO Wind and Tricera while a 25MW system commissioned two years ago was partially made up of second life batteries.
Second life BESS technology holds promise and will continue to be deployed as the stock of used EV batteries grows, but rapid price falls of new batteries and BESS has reduced the economic benefits of doing it (Premium access article).
One electric vehicle (EV) company executive working on energy storage recently told Energy-Storage.news that the firm had looked at second life BESS in great detail but that the maths behind it no longer added up.

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Postponed projects explain fall, ‘lumpiness’ to continue and international business more profitable than US
CFO Ahmed Pasha explained that the company’s results will continue to be ‘lumpy’ over the four quarters of the year as it works on a relatively lower number of very high-value projects, so project timing has a large effect. Put simply, revenues could differ greatly from quarter to quarter for the foreseeable.
Pasha went on to explain that the fall in Q3 was primarily down to the postponement by a customer of two projects that would have been worth US$100 million, and the signing of certain projects in its backlog were delayed. The reasons for the delay were nothing to do with interconnection issues, however, and more around “site readiness, civil works, permitting and the customer decision process”, Pasha said.
Interestingly, CEO Julian Nebreda confirmed an analyst’s suggestion that the firm’s international activities have a higher average selling price (ASP) and higher margins than the US business, and the higher weighting to international activities in the quarter explained the higher profits. “We have seen a lot of profit in the international markets,” Nebreda said.
The reasons include the fact that the firm’s offering internationally tends to incorporate engineering, procurement and construction (EPC) services as part of a more broader offering. The firm has also been actively selling its storage-as-transmission product, the Ultrastack, in the European market which has a higher ASP.
US cells
Fluence has also revealed that it has secured US-manufactured cells from AESC (Automotive Energy Supply Corporation), a joint venture between Nissan and Tokin Corporation which is building gigafactories in the US. Those cells will enable it to provide BESS that meet the criteria for domestic content tax credit incentives under the Inflation Reduction Act.
Several analysts quizzed Pasha and Nebreda about this. Nebreda said the cell costs were “very competitive” “and that “everybody realises this is the right move, and we’re ahead of everybody”.
In response to an analyst question around whether US cells could cover all its US demand, he also revealed that Fluence has contracted with AESC for two production lines and has the right of first refusal for any additional lines it brings up.
“So we have ample capacity to meet the demand that we see today and our clearly to meet our commitments,” Nebreda said, although not going as far as saying that would be true in future.
Later, he said: “It’s going to be a tight market, but I think that there will be enough to cover demand, though I don’t know about [if it will be as early as] 2026. But over time, we’ll have enough to cover the demand in the U.S. This is very important and it will happen. We will work to meet that demand.”
40% of US demand relates to data centres
Nebreda also said that 40% of its US projects were ‘indirectly’ related to data centres. By this, he meant that 40% of projects were being deployed to support renewable energy power purchase agreements (PPAs) being procured by big tech players to supply their growing data centre demand with clean energy.
SEC investigation and independent law firm enlisted
In February this year, short selling investment firm Blue Orca issued a short note on Fluence alleging numerous financial improprieties and major shareholder AES, and a US affiliate of its other major shareholder Siemens, were both unhappy with the company’s performance – something Fluence immediately denied.
In a 10-Q form filed along with Fluence’s results last week, the company said that, in response to that report, it completed an internal investigation with the help of outside counsel and forensic accountants.
“They looked at every comment and found they had zero merit,” Nebreda said in the call.
The Securities and Exchange Commission (SEC) is however conducting a formal investigation into the company, the 10-Q added.
“Although we cannot predict the timing or the outcome based on the nature of these matters and information requested by the SEC we do not expect it to have a material impact on our financial condition,” Pasha said in the call.
While the markets reacted negatively to the Blue Orca note at the time of its publication, they have reacted positively to the earnings release and discussion last week, trading around 10% higher than before it.

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The PHES plant comprises 10 fixed-speed units and two variable-speed units, all 12 of which have a power rating of 300MW. The variable-speed units are the first in China, and enhance the flexibility of the PHES to adapt to grid load and stability requirements.
It was reported two years ago that the project with all 12 units had been completed but updates since appear to contradict that.
For example, Austria-headquartered technology provider Andritz provided a variable speed unit for the plant and gave the following timeline:

15 March 2023: Stator lifted into pit
4 July 2023: Rotor lifted into pit
Mid-October 2023: The main installation work completed
Early November 2023: Dry commissioning completed
10 November 2023: Wet commissioning officially commenced
27 November 2023: First run of the unit
10 December 2023: First synchronisation test in turbine mode completed

Andritz said that the project saw it take a much greater role in whole power plant equipment commissioning than it had ever done previously. The company is working on several other projects in China too, as well as as in Turkey, Brazil and Scotland (with the Cruachan plant, covered by our sister site Solar Power Portal).
At 3.6GW the Fengning plant is larger than what is widely reported to be the largest existing PHES plant in the world, the Bath County plant in Virginia, US, which has a power rating of 3,003MW.
Larger projects are underway elsewhere, including the 5GW Pioneer-Burdekin project in Queensland, Australia. The Queensland government just announced that 5 kilometres of core samples have been collected and solid granite will now be confirmed structurally through the site.
China brought 6.7GW of hydropower capacity into service last year according to the International Hydropower Association, of which 6.2GW was PHES. It intends to reach 80GW of PHES by 2027 and a total hydropower capacity of up to 120GW by 2030.

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That’s a silly question, of course; there are plenty of components without which an energy storage asset, whether batteries, batteries in hybrid with generation, or using non-battery technology, can’t function.
But if you asked energy storage technology providers what the most overlooked component is in terms of its importance, the energy management system (EMS) might be a common response.
The EMS, sometimes also called the power plant controller (PPC), is essentially the software-based operating system and controls platform which simultaneously monitors, coordinates and optimises the asset during its lifetime.
Wärtsilä Energy Storage & Optimisation (Wärtsilä ES&O) has been in the game longer than most. Its GEMS Digital Energy Platform was originally developed by Silicon Valley energy storage startup Greensmith Energy back in the 2010s before Wärtsilä ES&O acquired the software-specialised system integrator and launched its own energy storage business.
Wärtsilä’s GEMS suite is now on its seventh iteration, as reported earlier this week by Energy-Storage.news as the platform was launched.
Its new features and updates are designed to enable effective control and dispatch in an industry of ever-larger battery energy storage system (BESS) projects, “multi-gigawatt-hour” projects in fact, while helping respond even faster to grid signals.
Combined value
A lot of the value that comes from energy storage is driven by the software and the EMS, says Wärtsilä ES&O’s head of software product management, Ruchira Shah.
“Storage, unlike a solar or wind plant or gas plant, doesn’t have intrinsic value in the same way, because it’s not a generator of energy. It is, at its heart, an arbitrage device, which means that it really matters when you charge and when you discharge and how you make those decisions,” Shah says.
“That’s all software.”
For example, the EMS can be the difference between responding in time to meet market requirements and not; a good EMS can “easily enable” operators to adapt to changing grid codes or when new market opportunities open up.
That doesn’t just apply to standalone energy storage projects; GEMS is an EMS from which any type of energy asset can be controlled, including the gas-fired engine power plants which Wärtsilä’s legacy business divisions manufacture and sell around the world.
It can also mean the coordinated control of, say, solar and energy storage within the same portfolio, or even the same power plant or microgrid. That, again can mean economic value as well as operational efficiency, and in the case of renewables, making low-carbon energy dispatchable.

Wärtsilä GridSolve battery storage hardware at a large-scale project in Ruien, Belgium. Image: Wärtsilä
“Solar is not a schedulable asset, it’s going to produce when it produces, and as an operator you can curtail it, but you can’t make it produce more,” Shah says.
“The interesting thing is that when you combine different assets, like when you combine solar and storage, all of a sudden you can now support, say, a power purchase agreement (PPA) requirement that is looking for firm output in, say, a specific time period that with solar alone, you can’t meet.”
“We support a range of different asset classes, including solar, wind, storage and engine power plants and then we support a range of different markets. I think the challenge for any software player is to be able to understand how those asset classes intersect with that market and also what opportunities you can have when you combine different assets.”
Multi-GWh scale projects
In a 2022 interview with this site, Wärtsilä ES&O head Andy Tang spoke about how average customer product sizes had moved from single-digit megawatt-hours of capacity to double digits and were already at around 100MW/200MWh.
This had been especially true in the US and Australia, two of the markets where the company is most active. Since that interview, the trend has continued, to the point that the GEMS 7 platform is designed to be suitable for projects that go into the multiple gigawatt-hour scale.
“Things are moving so fast in the industry that it’s tough to predict with certainty what projects are going look like in two to three years,” Shah says, but in the case of the rapid evolution of project sizes, the message from customers and the market was clear.
“This was a little bit easier, in the sense that we could see larger projects in our pipeline, and it takes a while for these projects to reach the contract stage, then once they’ve reached the contract stage, there’s often a couple of years before they actually commission them,” Shah says.
“There’s a fairly long lead time. So, in this case, it was a lot clearer where we had to go to. Looking at the pipeline, you had a sense that this is where we need the software to go in the future.”
From a technical perspective, delivering an EMS fit for very large projects is all about the “huge volume” of data that needs to be collected and actioned upon, Shah says, with data coming from metering systems, inverters and power conversion system (PCS) hardware, and of batteries, down to the module level.
That meant designing software and an architecture that could support that volume of data. At the same time, the new platform comes with new visualisations for large sites on the monitoring portal.
It enables users to “zoom out and see a full picture of the site, and then be able to zoom in to particular sections of the site within the user interface (UI),” Shah says.
Market needs faster response times
Wärtsilä claimed GEMS 7 comes with a number of other new enhancements, from upgrades to alarm and monitoring systems to features that enable automated cell balancing and state of charge (SoC) calibration.

GEMS rack at a BESS site in the UK. Image: Wärtsilä
Alongside those, the EMS is also designed to offer lower latency in responding to grid signals, in other words boosting an already split-second response times, which Ruchira Shah says is going to be vital for asset owners looking to participate in increasingly sophisticated classes of ancillary and system stability services applications.
There is generally in the global market a move towards faster response times and decreased latency, Shah says.
She offers the example of Australia’s National Electricity Market (NEM), where 60-second and 5-minute markets are now joined by the 2-second very fast frequency response (FFR) Frequency Control Ancillary Services (FCAS) markets and associated revenue streams.
“As you increase the number of renewables on the grid, and you decrease the number of spinning turbines which provide natural inertia to the grid, you need to replace that somehow,” Shah says.
“You need to be able to have batteries respond to frequency events faster and faster, and so I think that is why globally we’re seeing requests for shorter response times and markets created for assets that can respond faster and faster to the needs of the grid.
So that’s an important piece, a huge part of the core of GEMS, to be able to meet these new market needs and to be able to meet these new types of requirements in terms of reduced latency.”

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