The £300 million funding round was led by the UK Infrastructure Bank (UKIB) and multinational energy leviathan Centrica, supported by investors including Rio Tinto, Goldman Sachs, KIRKBI and Mosaic Capital.

The investment will enable the construction of one of the world’s largest long duration energy storage (LDES) facilities in Carrington, Manchester, using Highview’s proprietary LAES technology.

Once complete, Carrington – otherwise known as the location for Manchester United’s training complex – will have a capacity of 300MWh and an output power of 50MW per hour for six hours.

Construction begins on the site now.  Full operation is scheduled for early 2026. Over 700 jobs will be supported during construction and in the plant’s supply chain.

UKIB’s investment reflects its ambition to direct private finance to help new technologies reach commercial scale, as they aid Britain’s transition to Net Zero.

With its £70 million investment, Centrica comes on board as Highview Power’s strategic partner, supporting both Carrington & an accelerated roll-out of the firm’s technology elsewhere in the UK.

Highview believes its programme sets the bar for storage energy systems around the world, raising Britain to global leadership in energy storage and managing grid flexibility.

Highview Power is now at work planning four even bigger LAES plants elsewhere in Britain. The 2.5 GWh facilities, funded with an anticipated future £3 billion, will ensure a fast roll-out of the technology to align with the nation’s LDES (long duration energy storage) goals enabling the ESO’s Future Energy Scenario plans.

Highview Power has developed its LAES technology over 17 years. The technology can store renewable electricity for as much as several weeks, longer than electro-chemical batteries. The company says it is ready to be rolled out at scale, at key grid chokepoints.

Stability services to the National Grid including system balancing, feature among Highview’s business offers, speeding the redundancy of despatchable fossil fuelled power to manage demand volatility.

More manageable storage curbs curtailment costs, too. Last year British bill payers were caught on a £800 million hook, as stilled wind farms claimed compensation simply because the NG was too full to accept their low carbon output.

Highview Power seeks completion by 2035 of its larger UK installations, timed to meet one National Grid scenario of 2GW needed from LAES. That figure would represent nearly 20% of Britain’s energy storage for longer than two hours.

“There is no energy transition without storage” declared Richard Butland, pictured, Highview’s co-founder & CEO.

 “The UK’s investment in world-leading offshore wind & renewables requires a national long-duration storage programme to capture excess wind and support the grid’s transformation.

“UKIB, Centrica and our other partners are backing Highview’s ambitions to bring renewable energy storage into Britain’s economy at scale, liberating the potential of what is both the greenest and by far our cheapest energy source.

Centrica group chief executive Chris O’Shea enthused: “The energy transition is an opportunity that could transform lives. But with the UK’s changing energy mix, and more intermittency from renewables, we have to explore new, innovative ways to store energy so our customers have electricity available when the wind doesn’t blow and the sun doesn’t shine”.

Greater Manchester’s mayor Andy Burnham weighed in too. “My vision is for Greater Manchester to be a leader in the green transition. Highview Power’s decision to build one of the world’s largest long duration energy storage facilities at Carrington is a huge boost for the region.

“This new plant will deliver renewable energy to homes and business across our region and bring world-leading technology, jobs, skills and investment to Greater Manchester. I’m delighted to welcome Highview Power”, Burnham declared.

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The BM uses flexible assets – things that produce and consume capacity – like EVs, batteries and gas power stations to ensure supply meets demand, millisecond by millisecond.

An electric car-only combined unit in the mechanism will eventually see hundreds of thousands of Octopus customers participate as a virtual power plant (VPP). This is where digital technology enables all the cars to become like one large power station.

Since September the National Grid ESO has been running a trial using only Octopus customers, and their electric cars, to balance the Grid.   The trial’s success paved the way for other suppliers to do the same and offer a greener alternative to gas power stations.

Octopus customers taking part in the mechanism through the Intelligent Octopus Go tariff benefit from heavily reduced charging tariffs. Every bill payer benefits through a reduction in system balancing costs.

The trial has proved that many ‘mini power plants’ – electric cars – can be as useful as one big power plant. The only difference is that consumers pocket the cash for balancing the grid rather than big energy firms.

Extrapolating the results of the trial, if all 10 million EVs that are expected to be in the UK by 2030 participated in the Balancing Mechanism, system costs would be reduced by almost £100 million a year. They would also prevent abundant renewable energy from being constrained during low demand.

Octopus was the sole participant in the trial. Its experience showed domestic devices could balance the grid.

The trial ends in coming weeks, after which the company will share lessons and plans  with participants, discussing the implications for the industry.

The supplier’s head of flexibility Alex Schoch said: “We’ve empowered customers to take an active role in the energy system by standardising the process with National Grid and using cutting-edge technology. This will accelerate the transition to a cheaper and more sustainable future.

“This bottom-up approach to energy transition benefits consumers and drives down system costs, ensuring that everyone profits from the shift towards electric transport.”

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Extending volumes of power hosting for periods beyond two hours is seen as critical to extracting carbon from grids, and balancing a system increasingly reliant on intermittent generation from renewable sources.

Central to Whitehall’s latest thinking is developing a cap and floor price mechanism, analogous to the contracts for difference model successfully deployed in spurring investment to advance wind, solar and hydro electricity.

Deploying up to 20 gigawatts (GW) of long duration electricity storage will result, the document calculates, in system savings of up to £24bn, representing a saving to consumers of 3.3% of the total system costs.

Aimed at investors, power suppliers, storage project developers and technologists, consumer groups and network operators, the views-gathering exercise runs until 5 March.

The department’s call for evidence in July 2021 identified barriers to long duration storage including lack of certainty about revenues, high upfront capital costs and long build times.

Whitehall’s outline thinking offers suggestions for eligibility criteria to regulate participants in storage markets, as well as scenarios developed by D-ESNZ officials for their growth.

Industry and commercial interests have been increasingly pondering the steps needed in financial and technical engineering to bring forward grid-scale long-term power endurance in serious volumes. Consultancy McKinseys initiated its international research group in 2021.

Last winter, consultants Stonehaven advising ‘liquid air’ technologists Highview Power calculated that Britain had wasted as much as £ 60 billion over four winter months alone, through lack of long-term power storage.

Renewables and clean tech trades body the REA two years ago published its own thinking on long-duration power hosting and despatch.

Its head of policy Frank Gordon gave the ministry’s two-month consulation a warm welcome.

“The REA welcomes the publication of proposals to reward the considerable system benefits from longer duration energy storage systems with a new support mechanism. We need much more of this valuable resource, alongside all forms and durations of energy storage, to make the transition to a Net Zero energy system as smooth and cost effective as possible.

”We look forward to discussing the details with Government and our members and working together on implementation as soon as possible.”

Read the government consultation document here.

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The study, ‘Reform options for TNUoS and constraint management’ explores how rethinking the Transmission Network Use of System charges to accommodate low-carbon technologies could have as much of an impact on decarbonisation as the radical market reforms currently being considered by the government.  Such a re-jig could help achieve meaningful change in a much shorter timeframe, the energy think-tank asserts.

Conventional economic theory came up with the TNUoS charging framework, intended as a mechanism to recover from participants the costs of installing and maintaining Britain’s transmission cables, pylons and switches.

An ever more glaring fault in the set-up, however, is that it was designed to reflect a historic, centrally supplied market, rather than its dispersed, bi-directional future, as demanded by the nation’s transition away from polluting gas and coal mega-generators, towards potentially every hill and field making clean, carbon-free electricity.

Renewables generation, battery storage, and flexible demand are penalised unfairly by backward-looking charging conventions, Cornwall’s paper argues. The result is that fees imposed now on new technologies and ways of managing power flows often reflect unfairly their impact on networks.  In consequence, that spurs uncertainty and demotivation among investors.

The effect, says Cornwall, is increased costs today for all market participants, from generators to aggregators to end users  Worse, deployment is slowed of the clean generation sources essential to achieving Net Zero by mid-century.

The current set up fails too, Cornwall and SSE argue, to address networks’ growing need to cover rising costs of managing chokepoints and other system constraints.  These costs should be managed so they present low or negligible barriers to the electrification of demand, and to the UK’s faster adoption of renewables which Net Zero dictates.

Potential solutions to such costing dilemmas could be evolutionary and incremental, the paper claims, infilcting less pain than some market at present fear.  The analysts present the following innovations:

• TNUoS demand credits. These would see demand receiving credits in a similar way to generation in areas where they could benefit power grids.
• Tariffs specific to energy storage. A relatively small change to current TNUoS arrangements could see a set of tariffs created, expressly for energy storage sites. The tariffs’ design would mirror more closely the costs and benefits arising now from a system featuring growing numbers of grid-scale and near-grid-scale batteries.

Network economists and accountants need to think deeper, Cornwall’s paper urges, into new options that could address the cost of continuing constraints on the transmission network. Ideas advanced by the think tank include:

• Expanding the NG-ESO’s Constraint Management Pathfinder. Extending the National Grid ESO’s existing activities, such an expansion would see a wider application of the same approach to achieving or paying for more behavioural solutions, achieved without ‘big’ engineering or heavy capital spending.
• Rewarding demand management more richly through the Balancing Mechanism. Extending lessons learned from recent load-shifting trials on regional and national grids, more sensitive incentives should exist for conscious time-switching, as practised by heavy-using individuals including industries, and by their aggregators. Incentivising users previously thought too small or unsophisticated to dabble in the Balancing Mechanism would be part of this innovation.
• Improved data sharing by NG-ESO. Persuading or compelling the UK’s backbone operator to open its operational books in greater detail to market traders over longer timescales could foster more intelligent trading and minimise the need for expensive grid re-engineering.

Cornwall Insight’s principal consultant Adam Boorman opined:  “As the government considers revolutionary reforms in our energy market, there’s merit too in considering more gradual approaches. These can still deliver transformative results in less time and with minimal disruption.

“No single solution can comprehensively tackle the challenges of decarbonising the electricity system”, Boorman went on.

“But a combination of incremental changes to areas such as network charging can provide us with the means to make substantial improvements without the need for a protracted and costly overhaul of the energy system.”

From SSE, the paper’s sponsor, market development director Angus MacRae echoed the insight.

“The UK is rightly moving towards a strategic, coordinated approach to building the low carbon infrastructure required to deliver a clean, homegrown energy system, most notably with the accelerated deployment of the transmission network required to connect the huge wind potential across Great Britain.

“However, the current transmission network charging methodology….adds cost and risk to investment in renewable energy in the areas of greatest resource. Importantly it doesn’t incentivise investment in storage and flexible demand in areas where it is needed most.

MacRae added: “This report highlights a set of deliverable, incremental changes to transmission charges and balancing markets. They could unlock significant investment in batteries, hydro-pumped storage and hydrogen electrolysers in congested areas of the network.

“These changes will enable the better use of the deployed renewable energy capacity, reducing emissions and costs for consumers, without the delays and disruption to renewables investment that would come with more disruptive changes to the electricity market in Great Britain.”

For more information, write to this link.

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Flexibility services allow connected customers to support the management of the electricity grid and receive payment for doing so.

Today’s deal enables SP to simplify the procurement process for flex providers, removing the need to set up their operations through different, often hard-to-integrate trading platforms.

Flexibility provision, including time-shifting and offsetting, offers cash rewards to network managers and aggregators. But they complain high levels of complexity and lack of standardised interaction in trades put them off participating.

Piclo’s end-to-end service aims to reduce such barriers, ultimately supporting the transition to Net Zero at the lowest overall cost for customers.

As the first UK DSO to sign up to the expanded end-to-end services on Piclo’s expanded marketplace, SP Energy Networks can now dispatch and settle flexibility services, in addition to using the platform to advertise and procure assets to meet its network needs. This simplifies the process for FSPs when it comes to providing services to the Scots operator, enabling it to achieve flexibility at scale.

SP Energy Network’s recent contract agreement with Piclo will deliver the provider’s first end-to-end system covering flex procurement and operation. SP is currently seeking over 1.5 GW of capacity across more than 1,700 locations between April 2023 and March 2028.

SP Energy Networks will also be the first to operate low voltage flexibility services via Piclo across 122 locations from November this year, which will allow domestic customers to reduce their demand during peak times while facilitating short term markets to drive market liquidity.

Piclo’s Flex software enables system operators to secure energy flexibility from aggregated providers (e.g. EV fleet operators) during times of high demand or low supply. As of 2022, Piclo Flex has 60,000 registered flexible assets and flexibility contracts awarded totalling £60million with 16 GW of flex capacity registered and 2.4 GW+ of flexible capacity procured.

Gerard Boyd, SP Energy Networks’ head of flexibility, said: “Harnessing distributed network flexibility will be key in facilitating the transition to Net Zero, at the lowest overall consumer cost.

“We need to address the challenges that Flexibility Service Providers (FSPs are facing. The latest developments with Piclo are a game-changer for us.

Piclo CEO James Johnston said:  “We’re thrilled that SP Energy Networks is the first UK DSO to sign up for our end-to-end platform offering, resulting in a radically simpler and improved experience for FSPs. Our goal has always been to increase transparency and lower transaction costs for local flexibility markets.

Across the British Isles Piclo provides flexibility services to the UK’s national Transmission System Operator (TSO), plus DSOs UK Power Networks, SP, Northern Powergrid and Electricity North West.  ESB is the firm’s biggest Irish client.   Elsewhere New York State’s grid operation is a client, as are the equivalents in Italy, Portugal and Lithuania.

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The data reveals that, if flexible energy solutions are implemented, national wholesale and system electricity costs could be cut by an annual £4.6 billion in 2030 and £14.1 billion in 2040.

Households that participate in flexible electricity initiatives also stand to cut wholesale electricity costs by more than 14% in 2030 and a staggering 52% in 2040 – a predicted annual saving of £115 and £375 respectively for an average household.

The potential savings for households will be welcome news prior to the new price cap announcement on Friday 25th August. These are expected to show the cap remaining significantly above pre-2022 levels, with experts saying no respite is expected before the end of the decade and likely far beyond.

Typically, daily peaks in electricity demand occur in Britain on weekdays between 4pm and 7pm. To meet peak demand, additional fossil fuel-generated electricity is often required.

As these sources are more expensive than renewable options such as wind and solar, this drives up wholesale electricity costs and ultimately impacts consumer bills. With the anticipated increase in electricity demand over the next few years, this issue is poised to become even more acute.

Encouraging consumers to modify their electricity usage according to the availability or price of electricity, by, for example, installing smart meters so they can access time-of-use tariffs, and participate in trials like the National Grid ESO Demand Flexibility Scheme will boost off-peak energy usage, saving money and taking pressure off the grid.

Additionally, the report calculates that customers who adopt self-generation and energy storage for use during high-cost periods, stand to save hundreds of pounds from their annual energy bills. Even households that do not actively participate in household flexibility will see an overall reduction in their electricity bill as a result of a more efficient system.

The benefits would also be felt on a national scale; with the modelling showing that by embracing flexible electricity usage GB could avoid the need to construct the equivalent of four additional gas-fired power stations in 2030. This not only translates to cost-savings of over £2.5 billion but also provides significant environmental benefits for our communities. It would also reduce the need for upgrades to the electricity wires and infrastructure, which saves almost £1bn in 2030.

Figure 1: National & consumer savings under the flexibility scenario

Source: Cornwall Insight

​​​​Figure 2: Overview of total savings under the flexibility scenario, £bn


Source: Cornwall Insight
Anna Moss, Senior Consultant at Cornwall Insight said: “Our analysis has unveiled the immense potential of flexible household electricity use to support GB as it journeys towards a renewables-based system. By empowering consumers to become the architects of their own energy usage as well as supporting home decarbonisation technologies across the consumer base, the government can reduce expenses, alleviate strain on the grid, and even eliminate the need for additional costly gas-fired power stations.

“This is a defining moment in our energy journey. Britain is moving along the path to a more electrified future, where household engagement with flexibility will enable us to reach net zero at lower cost, allowing consumers to realise the financial benefits associated.

“Smart meters play a pivotal role in this transition, providing crucial data and insights that empower consumers to optimise their energy use.

“By embracing household flexibility, we not only revolutionise our electricity landscape but also rejuvenate our commitment to a greener, more sustainable future.”

Sara Higham, Director at Smart Energy GB said: “The debate on how we can meet the country’s growing demands for electricity often focuses on how we create more national infrastructure to generate more energy to meet demand, but this report clearly shows that there is another side to this debate: enabling and incentivising consumers to use the energy we generate in a more flexible way.

“This report clearly demonstrates the benefits of flexible energy use and the pivotal role played by smart meters in creating a flexible energy system. More than half of GB households now have a smart meter and the benefits to individuals and the country as a whole will only increase as installations continue.”

The full report can be read here.

​​In modelling the costs, the report makes assumptions about the future energy system. At the highest level, it assumed current policy aims continue, including:

• Achieving net zero emissions by 2050
• Decarbonising electricity by 2035

The report developed two scenarios to compare the benefits of enabling households to participate in a flexible energy system. In each scenario the report assumed a credible level of flexible technology uptake by households based on a current market view.

Flexibility Scenario – where customers take up smart technologies and Time of Use tariffs in line with the customer segments described above, and the energy demand associated with these can be used flexibly to support system needs and reduce customer costs.

No Flexibility Scenario – where customers take up technologies to meet net zero obligations (e.g. transitioning to EVs and heat pumps), but do not engage with flexibility opportunities and consumption patterns see limited change. We assume consumers in the No Flexibility scenario do not take up batteries, as these are primary used to access the benefits of flexibility.

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Located at Stony, Milton Keynes, the battery energy storage system (BESS) began its working life at the end of last month.

EDF now manages the device through its Powershift platform, accessing revenues and power trades including the Balancing Mechanism, wholesale deals and ancillary services.

The French-state dominated owner already manages two 20MW batteries in Britain on behalf of Gore Street. Adding 80MW in Milton Keynes brings the fund’s operational portfolio to over 370MW.

A leading operator of utility-scale batteries, Gore Street has existing installed capacity close to 110MW online in the UK, forming part of a 292MW operational portfolio across four national energy markets.

“EDF’s commercial offer represented best value for Gore Street Energy Storage Fund”, said Alicja Kowalewska-Montfort, technical principal at Gore Street Capital, the eponymous fund’s investment manager.

“EDF has a strong track record with two of our existing assets, making the agreement to take on Stony a natural progression based on consistently good performance.

Stuart Fenner, EDF’s director of wholesale market services, said: “We are very pleased that Gore Street Energy Storage Fund has once again chosen EDF as its trading and optimisation partner. We are committed to continuing to strengthen our relationship into the future.

“This partnership will provide essential flexibility to the energy system and reinforces EDF’s commitment to helping Britain achieve net zero.”

Gore Street Energy Storage Fund launched in May 2018, as the first such internationally diversified storage fund to be quoted on the London Stock Exchange. Its portfolio totals 1.17GW across battery storage facilities in Great Britain and Ireland, the mainland of western Europe and in the USA.

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The energyco has stolen a march on rivals by launching Max Power, its innovative tariff enabling supply origination and demand sharing across several locations, provided they’re hooked into a single corporate client.

Max Power allows businesses with two or more sites to send any excess renewable energy they’re generating to their other locations in the UK. Octopus estimates it could save some businesses as much as 25% from annual bills.

The model works, regardless of whether firms run their own generation from solar PV, wind turbines, hydro power, geothermal or even battery storage in one location, and share it with their other sites.

‘Panel Power’, Octopus’ existing smart export tariff, already pays solar-generating businesses 15p per kWh for unused power released to the grid.

‘Max Power’ goes further, so multi-site businesses can get the maximum out of the green power they generate by keeping it within their own business.

Octopus positions multi-site sharing of single-site self-generation as helping customers in sectors including retail, logistics, warehousing, FMCG and agriculture.

As ever, Kraken, the industry-leading fulfilment and billing platform around which Octopus functions, is behind the innovation, believed unrivalled among other green providers.  Kraken, was purchased in 2017, by Greg Jackson’s then one year-old debutant.

Kraken was essential to Octopus’ participation last month in National Grid ESO’s new ‘Demand Flexibility Service’, which paid businesses & households to shift consumption out of peak day parts.

Octopus Energy for Business CEO Zoisa North-Bond commented: “Businesses generating their own renewable energy can now bring their bills down further by sharing their cheap green power across their entire estate. Innovation like this puts money back in the pockets of British businesses and gives them greater control over how they use their energy. We’re showing that the greener choice can and should also be the cheaper choice.”

For more details, see here.

Max Power’s launch came the day before the supplier announced it had built Britain’s biggest Virtual Power Plant, yoking together more than 100 MW of EV batteries across the grid.

‘Intelligent Octopus’, another new tariff, is behind Octopus’ VPP success.  Charging vehicles at overnight off-peak rates, can saves electric car drivers over £760 a year, the firm maintains.

Leicester is this innovation’s chosen city of comparison.  The supplier says 100 MW managed by Intelligent Octopus is enough to run the Midlands community’s population of 370,000 for a full hour.

The power firm says its VPP capacity exceeds that of Britain’s current biggest battery now in operation, Penso Power’s 100MW facility at Minety, Wiltshire, funded by China’s Hua Neng Group and subsequently optimised by Shell-owned Limejump.  At stages during its implementation, Penso has earmarked the Minety facility for future expansion to 150MW.

Intelligent Octopus customers use Octopus’ app to set the time and amount they want their vehicle charged by. Kraken works in the background to automatically charge the cars up when there is abundant, low cost energy and when the grid is less busy, helping to balance out demand and supply on the grid.

By doing so, Intelligent Octopus is able to contribute to a flexible grid that doesn’t require expensive balancing costs – bringing down energy bills for everyone.

Octopus head of flexibility Alex Schoch commented: “We urgently need to build flexible grid technology to turbocharge the green energy system. The Intelligent Octopus tariff acts as a virtual power plant, shifting demand out of peak times and therefore cutting bills for everyone.

“As more electric cars take the road and steal market share from old-school gas-guzzlers,” Schoch went on, “we need even more solutions like Intelligent Octopus to handle the extra devices, increase the grid’s resilience and promote a green energy future.”

Correction:  An earlier version of this story incorrectly implied that the Minety 100MW battery is owned by Limejump.  The Energyst is happy to clarify the true position, which is that ownership of the facility continues to reside with Penso Power.

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Implying today that an accounting glitch lasting three and a half years was “inadvertent”, the group’s Pumped Storage entity today said it will pay £6.12 million into Ofgem’s voluntary redress fund.

Drax’s Cruachan pumped hydro plant, the group’s 440MW “hollow mountain” in Argyll, is the focus of the admitted excess BM claims.

Between January 2019 and last July, the generator unjustifiably sought re-imbursement from National Grid ESO for withholding or turning down output from the plant’s four turbines, at times when the grid operator signalled “transmission constraint”.

NG ESO manages “transmission constraint” among generators for all periods when electricity demand and potential supply appear likely no longer to match.  Causes might include localised maintenance or storms closing down transmission capacity away from a power plant.

Informed by the grid operator, generators can submit offer prices to turn up generation, or bid prices to turn it down. NGESO selects the bids on a competitive basis, according to prevailing needs on the nation’s system.

The supply licence which Ofgem grants to accredited generators includes a clause enforcing NG-ESO’s rights to manage such bottlenecks.  Condition 20A prohibits generators from being paid, or seeking to be paid, an excessive amount by NGESO during such periods.

The regulator’s enforcement director Cathryn Scott said today:  “Protecting consumers is a priority for Ofgem, and we will continue to monitor the wholesale energy markets in Great Britain and ensure their integrity on behalf of energy users.

“This enforcement action sends a strong signal to all generators that they cannot obtain or seek to obtain excessive benefits during transmission constraint periods. If they do, we have the powers to intervene and we are ready to use them”.

Since Ofgem raised the problem, Drax has worked with the regulator to set it right.  It has brought in new cost-based pricing rules, designed to reflect the costs and benefits to Drax of curtailing its generation.

Drax’s £6.12 million will be paid into the Voluntary Energy Redress Fund which Ofgem runs for the industry. It provides support for vulnerable consumers, as well as fostering innovation projects and steps to cut carbon emissions.

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Project Lion is a 250MW/500 MWh blueprint of permits and grid connections scheduled for energising in 2025, and anticipated to run until at least 2075.

Revenues from grid balancing and from arbitraging wind-generated power underpin Project Lion’s business model.

“Once energised, Project Lion will significantly contribute to increasing the UK’s energy independence and will help accelerate the increased penetration of renewable energy”, NextEnergy Solar told investors this morning.

The fund already operates 865 MWp of generation assets in the UK, Italy, Spain and Portugal.

With £300 million budgeted for the expansion, it will add to a 50MW battery being built in Fife, a 6MW project co-located at the iconic North Norfolk Solar Farm – adjacent site pictured – , plus a second joint-venture vehicle, to be owned 75% by the fund.

Partridge, in a North Norfolk Lion-related project

NextEnergy Solar currently sets a policy of battery assets composing no more than 10% of its gross assets, which primarily focus on clean generation. Project Lion breaches that threshold. The fund’s management company NextEnergy Capital will secure shareholders’ say-so, as well as rubber-stamping by the Financial Conduct Authority.

The fund’s chairman Kevin Lyon, commented on the short timeframe within which it had acquired battery assets:

“This acquisition of development rights adds significantly to NESF’s participation in the UK battery storage investment space.  The project will take our battery storage programme up to a capacity of 300MW, showing how NESF has been able to secure a significant development pipeline of storage projects”.

Kevin Lyon, Chairman of NextEnergy Solar Fund commented: “This acquisition of development rights adds significantly to NESF’s participation in the UK battery storage investment space.

“The project will take our battery storage programme up to a capacity of 300MW, showing how NESF has been able to secure a significant development pipeline of storage projects in a short timeframe.  NESF offers investors a unique investment opportunity, making a real difference in the transition to net zero.”

From the fund’s parent NextEnergy Group, CEO Michael Bonte-Friedheim highlighted Project’s Lion’s “enormous growth potential, with synergies to NESF’s current solar portfolio”.

“We look forward to constructing this project by 2025 and to operating it for decades into the future”, said Bonte-Friedheim.

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The mega-device is to be installed on Thinford Lane, and will plug into burgeoning offshore wind and supply, as well as facilitating new generation.  The developer applied to the county in January for permission, four months after a pre-application submission.

The 4.6 hectare plot is classed in the application as an agricultural field, nominally in a flood plain.  A new pond, linked to a sustainable soakaway and other sustainable drainage measures, is promised to draw away surface water.

Besides the pond, RES promises native trees will be planted and species-rich grassland protected.   Bat boxes and bug hotels are among measures to boost biodiversity on the site by up to 25%.

 Alan McMahon, the developer’s head of energy storage said: “ Systems like Spennymoor are essential for a stable and secure electricity system; the resilience of which is crucial for the UK’s future energy security.”

Thinford is 30 miles south of Blyth, landing point for the world’s longest undersea cable, the 700MW North Sea Link, completed last year by National Grid ESO in partnership with Norway’s transmission operator.

Founded four decades ago, multinational RES – or Renewable Energy Systems – says its 23GW of wind, solar and storage infrastructure delivered in 16 nations ranks it as the world’s biggest independent clean energy developer. Its UK base is in Hertfordshire.

Britain’s pipeline of unbuilt grid-scale storage devices swelled to an unprecedented 32.1GW in the twelve months to April, trade lobbyists Renewable UK reported.   Developers such as RES seek to expand on the nation’s 3GW of capacity already operating, or soon to be sparked up.

At 0.1GW, Spennymoor is among larger projects among that anticipated 32.1GW of UK hopefuls. Yet others out-muscle it.

Britain’s biggest grid-scale battery proposal known at present is developer Exagen’s intended 0.5GW/1GWh Normanton Energy Reserve storage unit, co-funded by Octopus.  A consultation among residents close to Earl Shilton, Leicestershire began last month.   Operation is intended for 2027.

In probable second place, Emirati-controlled port operator – and controversial owner of P&O Ferries –  DP World is paying Scottish-Australian power contractors InterGen a reported £200 million to install a 0.32GW/0.64GWh device at its London Gateway port in Essex.

Designed primarily for stabilising the national grid, DP World’s Gateway behemoth could in theory power up to 300,000 homes when fully charged.  Operation from a site in Thurrock is planned for 2025, assuming InterGen can find a partner willing to take 49% of the project.

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Now halfway through its planned twelve months, the operator’s £0.9 million SMITN project  – Smart Meter Innovations & Test Network – uses data from smart meters to give planners a wealth of deeper information, helping them to manage load when connecting low carbon technologies like heat pumps, home solar and power-trading batteries.

At SMITN’s beating heart is data spooling in increasing amounts and with greater accuracy off the DNO’s smart meters.  The information can help customers do a lot of planning research themselves, WPD argues, with user-friendly apps determining the specifics of what kit homeowners might connect, calling in aid tekkie arcana such as cable size and resistance.

Quality of power supplied matters too, alongside quantity. Micro-variances in frequency and voltage of grid supply can, under SMITN, help identify which customers are connecting low carbon devices and where extra capacity is needed. Thanks to new smart meter technology, WPD will be able to monitor flows and variances in greater granularity than before.

Since last September a £7.8 billion subsidiary of National Grid, Western Power Distribution invests £1 billion each year improving its network, serving eight million homes.  That cost makes up around 10% of a typical household’s power bill, or 27 pence per day.

Love my meter, love my data

Network upgrades, maintenance and workarounds can benefit from SMITN as well as homes, WPD innovation engineer Jenny Woodruff believes.

“The ultimate aim is to get the best possible data quality, not just for self serve”, said Woodruff, “but because we are going to need better data to support all sorts of different data applications” .

“When we have good quality data, we can do better network planning”, the WPD employee added. “We can do it safely, we can automate it, we can make sure phases are more balanced, we can make future networks more efficient, reducing the impact of faults and even predicting future faults.

“Ultimately, all this will save money and deliver a better service for our customers.”

The SMITN project aims to use data to confirm customer phases and feeders, permitting more effective load balancing.  Smart meter data can be used to predict more accurately local loads on low-voltage feeders and distribution substations.

Three lead partners assist the gridco with SMITN:

• Canadian-originated multinational CGI, experts in global smart networks and in addressing data and digitalisation transformations under way within regional grid operators, have led creation of the SMITN platform.
• Electronic designers Haysys perform data capture, yielding reference points for algorithms using its innovative devices, including one already existing and a second in development specifically for SMITN.
• Electrical engineers at Loughborough University will select the test network and advise on the algorithms for the trial.  Teasing out project learnings are the academics’ focus.

A fourth partner, GHD, will be working with WPD in an assurance role.

Workshops to which WPD will invite its DNO peers will smooth knowledge sharing.

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The installation next year at Alveston, Gloucestershire, next to turbines operating since 2017, will be a first UK battery installation for both parties.

The maverick supplier of wind- and solar electricity secured planning permission for a battery at Alveston as long ago as 2017.  Completion of the supplier’s own trading platform has been among factors behind the six-year wait.

Trading flex and capacity on wholesale markets, via fast response, short-term BESS (battery and energy storage systems) technology is the partnership’s objective.  It will use ABB’s proprietary optimization model to despatch the battery energy storage, according to system needs.

This morning’s announcement disclosed no financial terms.

Mark Meyrick, Ecotricity’s head of smart grids, said: “We’ve been working towards our first grid scale battery as we’ve been developing our Smart Grid platform.

“This project is a first for us and will enable us to manage demand for renewable energy, as well as develop a greater understanding of the deployment of storage for flexibility requirements.”

ABB was formerly known as the Swedish-Swiss combine ASEA Brown Boveri.  It bills its tie-up with the 26 year old Stroud-based supplier controlled by philosophy laureate Dr Dale Vince, pictured, as a ‘first in kind’.

Mark Meyrick, Head of Smart Grids, Ecotricity, said: “We’ve been working towards our first grid scale battery as we’ve been developing our Smart Grid platform – and we’re looking forward to taking this next step with ABB.  This project is a first for us and will enable us to manage demand for renewable energy, as well as develop a greater understanding of the deployment of storage for flexibility requirements.”

For ABB Electrification, Calogero Saeli added. ““As the UK continues its journey to net zero, ABB is excited to partner with Ecotricity on this 10 MW grid scale battery project, which will help to stabilize the grid. BESS is key to unlocking some of the challenges ahead, providing a highly effective way to capture clean energy and balance energy generation against demand to build grid resilience.”

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The energy market soothsayers advocate that as much as 18% of budgeted Whitehall support for new power tech should look to increase capacity, duration and speed of response among DNO- and backbone-facing storage assets.

The T4 Capacity Market auction for delivery in fiscal 2025-26 will add 2.6GW, bringing total storage across Britain’s grid system to 4GW.

That can only be the start, though, according to senior Cornwall modeller Tom Edwards.

Writing in the firm’s GB Power Outlook to 2030, Edwards says the growth in green tech shouldering the burden of generation, coupled with falling battery prices, point to increased importance for storage technologies.

Paying for the level of battery capacity Cornwall believes is necessary will cost approximately £20bn between 2025 and 2030.

“This is around 18% of the total investment which will be required in all technologies over the same period, including solar, wind, nuclear, and CCUS”, the analyst writes.

More renewable generation dispersed across the grid will leave it more exposed to both demand patterns and Britain’s weather.   “Perfect for storage” is Edwards’ summation.

“This will necessitate the development of backup technologies to carry the system through low wind and solar output periods, which could include long-duration storage, hydrogen, nuclear, interconnection, Carbon Capture, or unabated gas continuing to run at low load factors, offset by captured emissions elsewhere”, he predicts.

“Batteries won’t be immune either with development favoring two-hour and eventually four-hour battery applications”, Edwards concludes.

Read his analysis here

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From September, Centrica will begin trialling demand-side response (DSR) via remote control of storage heaters in social housing, dialling demand down and up as markets and networks require.

Detailed on Ofgem’s website here, this second trial uses Elexon’s Balancing and Settlement Code (BSC) Sandbox.  It allows innovators to trial concepts in a live market, without having to meet full BSC rules.

The first test was conducted by Emergent Energy, after Ofgem gave it the nod last May.

Centrica’s proposal will see it participating for two years in the Balancing Mechanism (BM) as a Virtual Lead Party (VLP), a role which Elexon and National Grid ESO created in 2019.  VLP status allows independent aggregators to offer services in the BM.

In partnership with Glen Dimplex, the Dublin-based privately-held power durables maker, September’s trial will initially bring into play up to 2.5MW of storage heaters in social housing, across sites fitted with Non Half-Hourly (NHH) boundary meters.

Boundary meters are used at points where sites – including complex ones and with multiple uses – connect to a distribution network.  Such meters measure electricity flows to and from assets on these sites.

Up till now the Balancing and Settlement Code has required that a site is settled half-hourly, before a VLP can operate assets located there.

Ofgem’s new derogation allows Centrica now to submit information stating when storage heaters have reduced their demand, as if the site had been settled half-hourly at the boundary meter.

They will do so using readings from meters built directly into storage heaters, thus  providing half-hourly data in place of readings from the boundary meter.

Elexon will carry out checks to ensure accurate figures are gathered remotely from heaters being switched down, up or off.

Sand out of the mechanism

A change in billing regulations next year means that market-wide Half Hourly Settlement (MHHS) will require that generation and use of power by customers with Half-Hourly capable boundary meters installed at their sites are settled using half-hourly readings.

A programme to upgrade boundary meters to achieve the required granularity will run till 2025.

Centrica believes consumers will benefit through participating in the trial. Pluses could include reduced tariffs or other benefits such as rent subsidies for customers in vulnerable circumstances and living in social housing.

For settlements arbitrator Elexon, the energy system will benefit from increased competition, leading to lower costs for system balancing.

Before the BSC recommended approval of the trial to Ofgem, Elexon carried out a risk assessment of financial and electrical factors. Risks to settlement processes and to other players in the BSC market were low, it concluded.

Elexon’s chief executive Simon McCalla declared: “We believe that DSR will play a big part in the transition to a cleaner, more efficient energy system. We are pleased that the BSC can support a trial which offers new ways for customers to participate in the BM.”

Stavros Sachinis, Centrica’s head of DSR & smart energy said, “We are delighted to have support from Ofgem and Elexon to enable Centrica and our partners in the trial, Glen Dimplex, to take a real step forward in accelerating the value of residential flexibility for consumers in the UK and putting households right at the centre of a more sustainable energy system.”

Muiris Flynn, chief technical officer at Glen Dimplex heating & ventilation arm, said “We are excited to be involved in this forward-thinking project, and look forward to demonstrating a model that offers real benefits to stakeholders throughout the energy supply and use chain. Enabling such functionality facilitates decarbonisation and will reduce costs for electric heating users.”

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