Nevertheless, higher shares of renewable energy bring new challenges to the system that must be addressed to not slow down the additional integration of renewable projects necessary to achieve targets set all around the world.
The current situation: Traditional renewable generation plants, which used to generate steady profit, are struggling. Power producers are suffering from severe curtailments in solar PV-rich countries, such as Chile and Australia, and in Europe we are already observing increasing numbers of negative price hours, especially around noon.
The implications: Renewable generation plants have lower revenues and weaker business cases because they face the risk of low, zero, or negative prices when supply is high (low capture price rate) and cannot adapt their production flexibly.
In addition, the existing electricity grid is also increasingly suffering from congestion due to local overproduction. This results in curtailments, stability issues and limited and/or costly grid connections for new projects or for the expansion of existing plants. These are clear signals that the market demands more flexibility and will also pay for it. Some countries, like Chile and the UK, are ahead of others in this development, making swift regulatory changes, while other regions are still lagging.
The challenge: Future energy markets need more flexibility and would have many different energy market products to organise grid stability and balance the system based on renewable and inverter-based resources. Power producers in this respect must plan and operate competently to be economically successful in these evolving markets.
This involves the ability to provide grid services, exploiting the opportunities in spot markets, and avoiding curtailments. This variety clearly indicates that the energy generation of the future needs flexible solutions.
The solution: True flexibility through hybrid power plants
Only hybrid power plants offer real flexibility and adaptability. These kinds of power plants usually integrate one or more technologies such as solar, wind and energy storage but operate as a single unit.
The main difference between hybrids versus standalone and co-located plants is the integration of generator and storage with the requirement of a joint dispatch. Hybrid power plants offer numerous advantages:

Optimised use of generation capacity: By combining different energy sources and storage capacity, usable production can be maximised by charging the storage with surplus energy, which can be otherwise wasted due to limited grid interconnection capacity.
Adjustability during operation: Hybrid power plants can respond faster to market shifts and weather situations compared to standalone renewable generators.
Multiple revenue streams: Hybrid power plants perform revenue stacking by tapping into different revenue streams, significantly increasing their profitability.
Balanced operation: The storage system can also be used to avoid imbalance costs or to create a more valuable production profile.

In contrast, standalone or co-located plants are often less efficient because they cannot fully utilise the benefits of integration and shared dispatching.
We recommend the following expert article: ‘Co-location vs hybrid: Is the future of power plants a battle of business models?’
Cost-effectiveness of hybrid power plants through optimised schedules and revenue stacking
Hybrid power plants have huge potential and untapped opportunities that many developers and investors are still unaware of or are just starting to explore.

CAMOPO optimises and executes the most profitable dispatch strategy. Image: CAMOPO
These types of plants can boost profits, which can be fully exploited through precise calculations and a deep understanding of optimisation opportunities. Hybrid systems can access multiple revenue streams and adjust to market conditions, making them more attractive and profitable.
Most importantly, their flexibility allows them to adapt to market and regulatory changes in the medium and long-term. This helps to lower the risk of investing in a renewable energy project.
What distinguishes hybrid power plants?
With the integrated energy storage capacity, smartly operated hybrid power plants can decide when and how to use the energy produced by the renewable generator.
In addition, they are also capable of providing certain grid services. This feature requires active and optimised operation management of the plant. This can be realised by using a sophisticated energy management system (EMS) with an optimisation algorithm which adapts the output of the power plant dynamically, based on current conditions.
Their secret to success:
Is called revenue stacking: The aim is to make the most out of the given flexibility and generate multiple revenue streams. This includes participating in wholesale markets, balancing markets as well as engaging in various grid services.
What they need to be profitable:
Optimise daily operation and adjust it to the real situation: Based on forecast data and the respective market developments, the energy management strategy must be adjusted continuously to achieve the best economic utilisation.
The following graphic shows a respective schedule for a PV + BESS project with revenue stacking approach, from our CAMOPO Optimiser:

As seen above, even this 48-hour period is sufficient to recognise the complexity of revenue stacking, which is only doable with an automated energy management system and optimisation infrastructure.
The logic behind hybrid power plants is that they are operated as a single unit and the dispatching must be optimised continuously. The number and possibilities of revenue streams vary depending on the country or grid’s regulation and market conditions.
Hybrid power plants are the future
Hybrid power plants are the future for independent power producers (IPPs), because they provide the necessary flexibility to respond to the rapidly changing conditions of energy markets. By combining different energy sources, such as solar PV and battery storage systems (BESS) or wind energy and BESS, hybrid power plants can maximise their production while minimising operating costs.
This flexibility allows IPPs to create multiple revenue streams by operating in different markets and offering additional services such as grid stability. In a market environment that increasingly values flexibility and efficiency, hybrid power plants are ideally positioned to offer sustainable and profitable solutions.
CAMOPO: one of the world’s leading hybrid optimisers
For several years, CAMOPO has been specialised in the optimisation of hybrid power plants with its software solution and operates worldwide as an independent product of SMA, yet benefiting from SMA’s substantial know-how of managing complex power systems.
CAMOPO, as an automated brain, plans, optimises and executes steadily the most profitable dispatch strategy and thus increases the return for investors and operators. Here are two reference cases that illustrate the effectiveness of CAMOPO:
Reference case 1: Chilean IPP
A Chilean IPP contacted CAMOPO to conduct an optimisation study. The aim was to increase the profitability of its planned plant (PV+BESS) through an energy management system (EMS). The results were impressive:

With 8% cost of capital, the net present value (NPV) of the investment would turn negative without an optimised strategy.
The expected internal rate of return (IRR) over the lifetime of the battery (15 years) increased by 4.6% with the optimised CAMOPO-EMS strategy.
With the optimised CAMOPO strategy, the NPV of the storage system increased by US$14 million to US$10.7 million, jumping strongly from the negative NPV zone to the positive, making the investment profitable.

Reference case 2: Power purchase agreement (PPA) with constant power output profile
An IPP wanted to build and operate a PV+BESS power plant to meet a PPA with a specific production profile:
The objective was to realise the specific production profile and avoid penalties for deviations from the profile. The optimised energy management strategy resulted in:

7% more revenue through improved use of generation capacity
Mitigation of penalties during operation

Up to 9% more IRR with hybrid and CAMOPO optimisation
In a case study for Pelion Green Future, involved in IslandGP, Tion etc., among others, it was investigated how an AC-coupled BESS addition can increase the profitability of a PV system.
The result: The IRR expectation for this battery investment is between 4.8% and 9%, depending on the scenario chosen and the use of multi-market strategies. Hear from our customer how they benefited from working with CAMOPO and the value that we added.
[embedded content]
The result
The future of power generation lies in hybrid power plants that combine flexibility and boost profitability. CAMOPO impressively demonstrates how optimised schedules and revenue stacking can make hybrid power plants profitable.
We invite all interested parties to a free initial consultation. Contact us at [email protected] to learn more and maximise the potential of your investments.
About the Authors
Isabella Caschetto is a product manager at SMA Solar Technology AG and responsible for CAMOPO.com, a commercial optimisation software for hybrid power plants. Her focus is on the development of digital products and business models related to the integration of renewables into the energy market. This includes especially solutions for the optimised plant operation of power plants. She has extensive experience in the energy market and energy management and previously worked as an energy consultant for industrial customers.
Dominic Multerer supports and advises CAMOPO on commercial topics with a focus on marketing, sales, and strategic orientation. He supports to integrate the CAMOPO software solution in SMA AG’s global solutions portfolio for Large Scale Projects. For CAMOPO, he is the first point of contact for interested investors, developers, IPPs, etc. With his experience in building new and digital business models, he is a valuable support to the team and is very familiar with the subject matter.

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Speaking earlier this month at the Energy Storage Summit Asia 2024, hosted by our publisher Solar Media, Zhao, who represents the energy storage arm of Chinese solar PV giant Trina Solar, said that cell-level innovations and improvements are vital in enhancing energy density, cycle life and safety of complete BESS solutions.
The company launched its second-generation containerised BESS solution, Elementa 2, in February of this year at our Energy Storage Summit EU in London, but quickly followed up the debut of that 4MWh, 20-foot containerised product with a 5MWh version in April at an event in the Middle East. Since then, the company has also launched a back-to-back version for the US market that combines two containers to form a 10MWh unit, with complete cell-to-AC solution integration.
The 4MWh version uses 306Ah cells, and the 5MWh uses 314Ah cells. Both are equipped with lithium iron phosphate (LFP) lithium-ion (Li-ion) cells, manufactured in-house by Trina Storage.
Energy-Storage.news has previously covered aspects of Elementa 2 and its predecessor Elementa’s complete system design and manufacturing, as well as Trina’s market strategy from ESN Premium interviews with Trina Solar executive president Helena Li and in reports around various projects.
However, at Energy Storage Summit Asia, Leo Zhao presented a deep dive into Trina’s cell-level innovations, noting their immediate impact on LCOS.
LCOS is defined as the total cost of the project over its lifetime—including capital expenditure (CAPEX) and operating expenditure (OPEX)—divided by the total energy throughput or energy discharged, again, over its complete lifetime.
Zhao told Energy-Storage.news that from Trina Storage’s OEM perspective, drivers to lowering LCOS include larger capacity cells, enabling more cycling and throughput, and reaching higher roundtrip efficiency.
“Underlying all of that is safety, because that guarantees the operation of the project over the designed lifetime,” Zhao said.
Pre-lithiation of cathode
Battery lifetime can be extended by improvements to any of the four major components of the cell, Zhao said, from cathode to anode, electrolyte and separator.
One major example of an advance that enables longer battery cell lifetime, is pre-lithiation of the cathodes.
“Pre-lithiation is technology to gradually release active lithium, to compensate for the loss of active lithium, to compensate for the loss of active liquid.”

Model of an Elementa 2 solution on display at All Energy Australia in 2023 ahead of its official launch this year. Image: Trina Storage.
Regular readers will note that rival Chinese manufacturer CATL recently launched a BESS solution, which the company claimed would experience no degradation in its first five years of operation.
How CATL had achieved this had been a source of speculation around the industry, before it was revealed in June that one of the manufacturer’s main strategies was, similarly, pre-lithiation.
“There are many different ways to do pre-lithiation,” Trina Storage’s Dr Leo Zhao said.
“For this particular technology, we’re working on adding extra additive materials to the cathode so that, especially at the beginning of cycling, this gradually releases extra lithium into the lithium-ion battery to overcompensate for the loss of active lithium. This can reduce degradation and also enhance the life cycle.”
This type of benefit which can sometimes be a complex proposition to understand, Zhao said, can be explained to customers in the way it directly translates into lowering the LCOS.
“We can always associate it back to earlier discussions around LCOS, because if we can ensure longer life cycles, and lower degradation, that will make sure that there’s more energy throughput over the lifecycle of the project,” Zhao said.
“This will be associated with and translated directly to the battery’s warrantied cycles. From the OEM’s point of view, how many cycles can be warrantied for the project, and how many cycles the product can be used for. This is directly translated to the warrantied usable capacity of the product because that’s associated with State of Health (SOH) and also how much is being guaranteed.”
Trina Storage head of BESS solution engineering, Beyond Li, will speak about Elementa 2 and BESS design and innovation in a sponsored Energy-Storage.news webinar tomorrow, 31 July 2024 (1pm BST, 2pm CET). Register here to attend ‘From cell to complete AC system integration with Trina Storage Elementa 2’, or to watch on-demand after the live broadcast.

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Renewable generation now accounts for 22% of Honduras’ electricity mix, but growth has been limited by its transmission system operator (TSO) CND to ensure quality and security of supply. Energy storage will be key to continuing to ensure that while increasing renewables, the CREE said.
“The integration of Energy Storage Systems (ESS) in the national electrical system represents a key strategy to increase the stability, efficiency and sustainability of the electricity supply in Honduras,” said the CREE in its consultation document.
“Given the energy transition scenario and the growing contribution of energy generation from intermittent renewable sources, ESS emerge as important technical solutions to guarantee the continuity and reliability of the electrical service.”
But to enable that integration the current framework needs to be changed. “The CREE has identified that the current regulatory framework should be reviewed to identify possible barriers to the integration of ESS, as well as gaps in the regulation that should be filled to allow and facilitate the development and installation of ESS,” it said.
Read the CREE’s consultation outline, in Spanish, here. The actual acronym used by CREE is SAEs, which stands for the direct translation of ESS: Sistemas de Almacenamiento de Energía.
CREE said that energy storage could be deployed as part of hybrid power plants, combining with generation resources, as standalone transmission and distribution (T&D) assets, or as user installations allowing energy consumers to manage their usage.
One change to the regulatory framework could be allowing hybrid plants to be remunerated for the firm, dispatchable power that energy storage would enable them to produce. However, the CREE also said that it is considering barring co-located energy storage systems from charging from the grid. Such a rule is typically only employed for specific subsidy schemes.
Another change would be allowing energy storage systems to be developed as transmission assets.
The scope of the review appears to be technology-agnostic in terms of its definition of energy storage, comprising lithium-ion, pumped hydro energy storage (PHES), compressed air energy storage (CAES) and ‘others’. “All different types of storage systems will be treated interchangeably as ESS,” CREE said.
CREE added that the electricity market in Honduras has similar conditions to those in Chile and Colombia when they were first developing their energy storage markets.

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NHOA said the fall was ‘entirely attributable to the industry-wide drop in system prices deriving from a welcome rapid degression in battery prices’, a trend Energy-Storage.news has reported on extensively (Premium article).
Including its EV charging solutions divisions Atlante and Free2move eSolutions (a joint venture with OEM Stellantis), group revenues were €124 million, up 7%, with Free2Move doubling its figure to €32 million. The group is in the process of being bought out and de-listed by its parent company Taiwan Cement Corporation (TCC), pending regulatory approval.
For NHOA Energy, EBITDA for the period was €4.4 million while net income was positive, and it increased its operational projects deployed by 344% to over 1GWh with another 1GWh under construction. It commissioned a 120MWh BESS for TCC in Taiwan in April, and won contracts for a 50MWh system in Italy and a 313MWh system in the UK.

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Tesla said it deployed 9.4GWh of utility-scale Megapack battery energy storage systems (BESS) and residential Powerwalls in Q2 2024. In Q1, that figure was 4.1GWh, beating its previous record in Q3 2023 by 100MWh. The latest numbers also showed a 158% increase in deployments year-on-year, from 3.7GWh in Q2 2023.
To give further context, the company reported a total of 14.7GWh storage deployments for the full-year 2023.
That performance drove Tesla’s energy business segment’s most profitable quarter to date, and CEO Elon Musk said in an earnings call with analysts that potential demand for energy storage is widely underestimated.
Tesla’s Megapacks are currently produced at a single factory, in Lathrop, California, and shipped worldwide, but a new production plant, in Shanghai, China, is on schedule for opening in Q1 2025, the company claimed.
Lathrop, meanwhile, will be fully ramped to 40GWh annual production capacity by the end of this year.
“I think people don’t understand just how much demand there will be for storage. They really just… like the people, I think, are underestimating this demand by product order of magnitude,” Musk, who is also Tesla’s chief product architect, said.
Musk gave the example of the US power grid, noting the “huge gaps” between peak demand and energy supply. He described how the grid has to “support the load at the worst minute of the worst day of the year,” in order to not have blackouts.
Tesla CFO Vaibhav Taneja said that the company’s “energy storage backlog is strong,” although investors can expect some fluctuation from period-to-period in recognition of orders, deployments and revenue from storage.
While in recent quarters, Tesla has heavily emphasised the contribution from Megapack large-scale deployments to its reported figures, Taneja noted that Powerwall also drove activity in the segment in Q2.
Vertical integration is ‘a unique proposition’
Colin Rusch, a stock analyst with Oppenheimer & Co, asked about Tesla’s strategy around the potential saturation of key energy storage markets, “given that some of these larger systems are starting to shift wholesale power markets in a pretty meaningful way quickly,” as well as how the company planned to remain competitive in the face of growing competition on the supply side.
Taneja and other executives replied that one of the Megapack’s strengths was in Tesla’s full integration of hardware including power electronics and site-level controls, as well as the solution’s software stack.
The CFO claimed that to be a “unique proposition” within the storage space, while Musk claimed customers often try and put together “a hodgepodge solution,” presumably attempting to integrate different hardware and software technologies at site or portfolio level.
“And then that doesn’t work, and then they come back to us,” Musk said.
According to Tesla, saturation of markets is not really happening on a global scale, although it may be in some limited pockets—the UK might be a contemporary example of this—but owing to the huge, often underestimated demand Musk spoke of, the company expected to see different markets open up around the world.
End of IRA subsidies ‘may help Tesla long-term’
No Tesla earnings call would be complete without a statement or two from Elon Musk that might be considered provocative or controversial.
This time out, that talking point, or perhaps one of them, would be the CEO’s view that, having endorsed Donald Trump in the US presidential race a few days ago, the cutting of Inflation Reduction Act (IRA) subsidy policies would not have a major impact on Tesla’ business.
Colin Langan, stock analyst at Wells Fargo, asked what the company thought the impact would be, in the context of some of Tesla’s EV models as well as battery production benefiting from tax credits.
“I guess that there would be like some impact, but I think it would be devastating for our competitors and for Tesla slightly,” Musk said.
“But long-term probably actually helps Tesla, would be my guess, yes.”
Musk then went on to say that the value of Tesla long-term is closely aligned with its ambitions in autonomous vehicle driving and that “all those other questions are in the noise.”
CFO Taneja clarified that Tesla planned its activities irrespective of “whether or not the IRA is there”.
“That’s the way we’ve always modelled everything. And that is the way internally, also even when we’re looking at battery costs, yes, IRA, there are manufacturing credits which we get, but we always drive ourselves to say: ‘OK, what if there is no IRA benefit? And how do we operate in that kind of an environment?’
See Tesla’s Form 10-Q filing of financial results for Q2 2024 with the US Securities and Exchange Commission (SEC).
Conference call transcript by The Motley Fool.

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ACEnergy submitted a State Significant Development application (SSD) to NSW Planning for the BESS earlier this year. An SSD provides an alternate approval pathway for projects or sites considered to have state significance.
As part of this application, the Planning Secretary issued a Secretary’s Environmental Assessment Requirements (SEARS) assessment, which specifies what issues must be addressed in the Environmental Impact Statement.
ACEnergy is an Australian renewable energy developer which to date has delivered more than 30 projects, totalling 1.1GW of capacity and has a development pipeline of 2.7GW, according to the company’s website.
ACEnergy lists seven large-scale battery storage projects in development across various Australian states, as well as a partnership to deliver distributed-scale energy storage with investment group Sustainable Energy Infrastructure (SEI).
ACEnergy’s proposed payment less than 30% of current levy
For the construction of the project, ACEnergy would be required to pay a development levy, which, under Leeton Shire Council’s Section 7.12 Plan, amounts to 1% of the development cost. In this case, ACEenergy would be required to pay the council AUS$2.5 million.
In a bid to reduce this amount ACEnergy, the developer submitted a Voluntary Planning Agreement (VPA). This deal would have seen the company pay AUS$730,000 over five years – 29% of the traditional VPA.
Indeed, ACEnergy proposed an upfront payment of AUS$250,000 at the commencement of the project’s commercial operations. A further AUS$480,000 would then be paid at the start of the fifth year of operation. The company also said it should be excluded from the mandatory development levy as it is also establishing a community benefit fund to support the local population.
The Council rejected this proposal and reached a decision at a meeting last week (24 July). According to a statement released by the council, the councillors felt the 1% in developer contributions would go a long way in providing funds for public facilities and other long-term development pressures. The council also believed the figure is a “reasonable amount relative to the size of the project”.
During the council meeting, a key point raised was the unfairness of expecting potential home builders to pay the same levy to construct a property, regardless of their financial stability, unlike ACEnergy, a large corporation.
One councillor said: “The VPA is not even 30% of what they would have paid under our contributions. This development has an estimated development cost of around AUS$250 million.
“The developer is a very big corporate body. If mums and dads built a new home in Leeton, they buy a 1% contribution. It’s just as hard for them to pay as it is for this company to buy theirs.”

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FDRE tenders seek to guarantee the supply of renewable energy to entities connected to the Inter-State Transmission System (ISTS) across India, particularly at times of peak demand when solar PV may not be generating. As such, bids require an energy storage component to make the renewable power dispatchable.
In the case of the latest round, the fourth held by SECI to date, energy must be dispatched at an 80% Demand Fulfillment Ratio (DFR) in hourly blocks between peak hours from 1 April to 31 October. These are defined in SECI documents as 00:00 to 01:00, 14:30 to 16:30, and 21:00 to 24:00 each day during that period.
During the rest of the year, resources must deliver energy with a DFR of 90% on a monthly average basis.
Five bidders were awarded capacity, with tariffs of IR4.98/kWh (US$0.059/kWh) for the lowest three and IR4.99/kWh for the remaining two. They can be seen in the table below. Serentica Renewables bid with 250MW, but was awarded 100MW, as the above bidders already accounted for 530MW of the total 630MW up for award.  
BidderQuoted tariff (IR)Loaded tariff (IR)Bid quantityVena Energy4.984.98100MWHero Solar Energy4.984.98100MWJSW Neo Energy4.984.98230MWHexa Climate Solutions4.994.99100MWSerentica Renewables 4.994.99250MW (100MW awarded)
Frameworks for the award of Firm Dispatchable Renewable Energy on a competitive tariff-based bidding model were published by the Union Government of India’s Ministry of Power in 2023.
While as of last month, a total of 10 tenders had been launched by various state agencies including SECI and power producer NTPC, totalling 12.1GW of renewable capacity, they have faced a few challenges along the way, in some cases requiring reconfigurations and amendments to make their terms less demanding for developers.
Expert Debmalya Sen, India lead for advanced energy solutions at the World Economic Forum (WEF) noted in a LinkedIn post that PPAs have been signed for 1.2GW to date, just over 8GW has been awarded or in the RFP stage, while 3.7GW has been cancelled.
For instance, from a 3GW NTPC tender and 1.5GW tendered by SECI in its second round of FDRE tenders, only 2.1GW was awarded, Sen noted.
For the newest FDRE IV procurement, SECI made some amendments between its launch in September 2023 and the reverse auction this week.
These included making the peak time DFR ratio less demanding, bringing it down from 90% to 80% and reducing the tendered amount from 1260MW to 630MW. The load profile was also changed from 15-minute to hourly blocks.
BRPL and BYPL will procure 625MW of dispatchable capacity and GIFT Plc 5MW.
The DFR will be furthered reduced for FDRE V, which Debmalya Sen commented may lead to a still lower price discovery for tariff bids.
Further information on SECI’s FDRE IV tender can be seen here.
Sterling & Wilson awarded 1,000MWh BESS EPC contract
Engineering, procurement and construction (EPC) firm Sterling & Wilson’s has been awarded a contract for 500MW/1,000MWh of standalone battery energy storage system (BESS) project work in India.
The India-headquartered firm’s renewable energy arm made the announcement today to the National Stock Exchange of India, noting that this would be the country’s largest BESS project to date, due to be executed by the end of 2025.
The firm said in the same announcement that it has also been awarded a contract to work on a 20MW floating solar PV project in the state of Karnataka. According to Sterling & Wilson, the total value of the two contracts is around IR3.28 billion (US$39.16 million).
The EPC contractor said both project orders came from the same client, but did not name it. However, according to a source Energy-Storage.news spoke to, it is very likely to be JSW Renew Energy Five, a subsidiary of JSW Energy, which is in the portfolio of Indian conglomerate JSW Group.
JSW Group won SECI’s first pilot tender for standalone battery storage, splitting the 1,000MWh capacity across two equally sized 250MW/500MWh projects, as reported by this site in January 2023. This is thought to be the project that Sterling & Wilson referred to. In addition to EPC work, Sterling & Wilson Renewable Energies will also carry out testing and commissioning of the systems.
India’s energy storage tenders, including FDRE, round-the-clock supply and standalone BESS tenders have been credited with kickstarting the country’s market and bringing down prices.
As of March this year, around 219MWh of BESS was online across the country, mostly paired with solar PV, but with India’s government targeting 500GW of new non-fossil fuel energy by 2030, including 450GW from solar PV and wind, the need for storage is acute, while beyond the 2030 timeframe, the national Central Electricity Authority (CEA) has modelled a need for 320GW/2,380GWh by 2047, about two-thirds from batteries in megawatt terms and the remainder from pumped hydro energy storage (PHES).

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The company won the contract from BESS developer and operator Jupiter Power two years ago shortly before the companies announced an agreement to deploy 2.4GWh of BESS projects utilising locally manufactured technologies.
They claimed that, as for a project Energy Vault deployed for utility NV Power in Nevada earlier this year, the commissioning process for the St Gall project was a streamlined one. Earlier this year the firm won another 400MWh project from Jupiter Power.
The battery modules for the St Gall project were provided by Chinese battery OEM Rept, as shown in close-up picture (below) of the BESS containers from a video on Energy Vault’s website.
Energy Vault is primarily known for its gravity-based long-duration energy storage (LDES) technology but in the last two years has moved into deploying BESS as well as green hydrogen multi-day energy storage. CEO Rob Piconi told us in an interview last year that this was because the demand in the LDES space hadn’t taken off as fast as expected.

Image: Energy Vault corporate video.

The firm did however see its first large-scale commercial project using its gravity tech commissioned recently, in China, and has partnered with an architecture firm to explore deploying it in skyscrapers.
The company provided an update on its strategy in a recent investor and analyst day, outlining three key tenets for its strategic focus: addressing the world’s largest markets and growth regions, delivering more predictable and recurring revenues, and delivering strong growth and profitability.
It expanded into the Australian market earlier this year with a project order, but revealed that revenues in 2024 would be substantially lower than predicted.
The company is also expanding into asset ownership, initially through a project in California combining BESS and green hydrogen. It would not be the first LDES company to move from being a technology provider only to fully owning assets, with others including vanadium redox flow battery (VRFB) firm Invinity.

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This was more than enough to offset a major increase in energy costs of 155%, or AU$10 million, from the same period of 2023, AEMO said.
Indeed, energy trading continues to become a larger proportion of the revenue stack for battery storage systems than revenue secured through frequency control ancillary services (FCAS), a type of service controlled by the AEMO designed to secure the security of supply and prevent blackouts and power failures.
Total estimated net revenue for NEM grid-scale batteries this quarter was AUS$41.2 million, an increase of AUS$13.6 million from the AUS$27.7 net revenue earned in Q2 2023.
AEMO’s report revealed that FCAS revenue increased steadily YoY, with an increase of AUS$1.1 million, around 7%. However, this ultimately led to a YoY decrease in the proportion of overall revenue deriving from the FCAS market, with it down 39% in the quarter compared to Q1 and down from 54% in the previous year.

Image: AEMO.
As seen in the graph, Australia’s NEM, which covers the south and east of the country, has become an increasingly volatility-oriented market for BESS owners. Since Q2 2021, when energy market trading stood at less than 20%, it has grown to take up a much greater market share, around 60%.
Research conducted by Rystad Energy last year (October 2023) revealed that, amongst the 39 global electricity markets, NEM was identified as the “most volatile”, with the organisation stating that there was an urgent need for energy storage to mitigate this.
Drivers of the volatility being seen are primarily due to outages at coal power plants, the impacts of natural disasters on transmission infrastructure and the increasing penetration of variable renewable energy on the grid, mainly from solar PV. As such, Rystad concluded that by 2050, balancing the NEM will require 46GW/640GWh of energy storage.
It is worth noting that the volatility seen in the NEM is attracting international companies seeking to ply their trade in Australia. For example, as reported by Energy-Storage.news in 2022, Ireland-headquartered smart energy company GridBeyond entered the market, citing growing electricity supply volatility and the rising demand for distributed energy solutions in Australia as amongst their motivations.
New South Wales leads net revenue margins
From amongst the states connected to the NEM, including Victoria, Queensland, New South Wales (NSW), South Australia and Tasmania, NSW’s BESS assets captured the highest net revenue, around AUS$13.4 million – a 341% increase compared to Q2 2023’s AUS$3 million net revenue margin.
Of this figure, around AUS$11 million came from energy trading and AUS$2.4 million from FCAS markets.
The second-highest increase in net revenue figures came from Queensland, which saw a jump from AUS$4.7 million in Q2 2023 to AUS$10.3 million in this quarter. Most of this revenue, at AUS$6.7 million for the quarter, arose from contingency FCAS revenue.
There was also a YoY increase during the morning and evening peaks in this quarter. This increase is driven by the availability of additional batteries and higher spot prices. However, higher energy costs associated with charging offset the increased revenue earned when charging at negative prices (+AUS$0.5 million), resulting in a decrease in net revenue outside peak periods.

Image: AEMO.
Pumped hydro energy storage net revenue sees a vast increase
Alongside battery energy storage, pumped hydro energy storage (PHES) saw quarterly revenues rise by AUS$22.4 million year-on-year, representing a 76% increase.
The increase in spot prices corresponded to that rise, especially due to spot price fluctuations in NSW. Shoalhaven, a 240MW project, saw revenue from prices exceeding AUS$300/MWh, up AUS$14.9 million, around 468%, to reach AUS$18.1 million this quarter. Overall, Shoalhaven’s estimated net revenue was AUS$24.4 million, marking an AUS$17.1 million (235%) increase YoY.

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The City of Riverside’s first RA contract requires Ormat to bring the project into operation by the guaranteed commercial operation date (COD) of 1 March 2026, although the company said it expects to be able to do so earlier, by the end of 2025.
Ormat develops, owns and operates geothermal energy projects, with additional business lines in waste-to-heat and energy storage technologies.
The energy storage division opened in 2020, following the company’s 2017 acquisition of energy storage developer Viridity. Ormat decided to enter the market to broaden its revenue base and noted in 2020 that the COVID-19 pandemic impacted revenues from its geothermal power generation and development as well as waste-to-heat generation.
To date, it has 190MW/318MWh of operational BESS assets in its portfolio, with projects in states including Texas, California, Ohio and New Jersey. In mid-2023, Ormat CEO Doron Blachar said the company was on-track to achieve a growth target that would bring its portfolio to 500MW-530MW and over 1GWh by the end of 2025.
Ormat CEO: ‘Segment transitioning to higher-growth’
At a 20 June 2024 Investor Day at the New York Stock Exchange (NYSE), where the company’s shares are listed, Ormat’s EVP of energy storage and business development Ofer Ben-Yosef said that the division has 335MW/1,040MWh of projects under construction which are scheduled to be online by the year-end 2025.
Energy storage comprised just 4% of the company’s total revenues in 2023, but Ormat sees it as a high-growth potential business, with Ben-Yosef pointing to market tailwinds such as the investment tax credit (ITC), the forecasted continuing growth of renewable energy deployments and equipment cost reductions.
Ormat also expected to see an ongoing shift in California and Texas from merchant opportunities to contracted revenues, noting that prior to 2023, California mostly saw 10-year RA deals with merchant upside, and the Texas market was pure merchant.
Post-2023, California will be characterised by up to 20-year tolling PPAs or RA contracts of between 10 and 20 years, with merchant upside, and Texas by tolling PPAs over 5-year to 7-year terms. RA and tolling agreement prices have risen by 20%-30%, Ben-Yosef said.
The company is also transitioning to executing larger projects, from average project sizes of 7.5MW/15MWh in 2018 as it entered the market, to 75MW/220MWh between 2024 and 2028.
While its other divisions are internationally diversified, Ormat Technologies’ energy storage division is focused on the US and has a claimed pipeline of 3.5GW/12.2GWh, of which California accounts for 2,105MW/8,420MWh of its development opportunities.
The company claimed 100% of its projects under construction as of Q1 2024 are eligible for the ITC. The Shirk project in Visalia for the City of Riverside is ‘currently expected to be eligible’ for a 40% tax credit, Ormat said in its announcement this week.   
“The Shirk project shows the continued progress that Ormat has been making towards aligning our strategic growth focus to capitalise on key target markets in the US, such as California, while also transitioning our energy storage business to become a higher-growth segment with a balance of contracted revenues,” CEO Doron Blachar said.

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