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 Electric Thames project is a collaboration of the south-east’s distribution grid operator UKPN, low carbon innovators Marine Zero and consultants LCP Delta.

Reducing carbon emissions in a city once known as The Smoke, the trio foresee electric-powered vessels helping to power London’s energy network, at least at the margins, and generating income for commercial vessel operators on the Thames.

Amps caught, at Amp-ton Court  

Still on the drawing board, the parties’ feasibility study is now running the numbers on using electric vessels to feed stored power back into the capital’s electricity network, accelerating the transition to Net Zero.

Expanding city-wide the principle of home night storage heaters, battery-powered vessels on the Thames could store green energy when the wind blows or the sun shines, then feed it back to the grid during peak electricity hours.

Cruising for coulombs

The approach could help increase the capital’s flexible energy capacity and reduce peak electricity demand.

The Electric Thames venture complies with the Port of London Authority’s intention annnounced in February to reach Net Zero in the river’s operations by 2040.

Its research centres on scaling up electric riverine transport, from easily converted pleasure cruisers, to diesel-powered pilot boats, tugs and commercial freighters.  Even the 50 barges run every day by Cory Group to collect non-recyclable waste from depots at Wandsworth, Barking, Battersea and others, are believed to fall within the study.

Funded by Ofgem, Electric Thames’ discovery phase ends next month, as it assesses responses from vessel and quay operators, mapping out their power needs.

Insights yielded will allow UKPN to plan works needed to facilitate the move to cleaner vessel and transport operations on the Thames.

Take me to the river, drop me in the water

Passenger carrying boats powered by electricity are a growing market.  In Berlin at least one operator hires out electric cruisers by the hour to tourists.

Swedish boatmaker Candela builds a range of battery-powered hydrofoils. Lifting away from the water’s drag, its new P-12 model takes only 16 seconds to reach 30 knots, carries the same number of passengers and joins Stockholm’s mass transit system this year. Founder Gustav Hasselskog blogged recently; “We’re jump-starting production to keep up with demand.”

Back on the Thames, UK Power Networks’ head of innovation Luca Grella said: “This is a first-of-its-kind project in Britain, and one that is operating at the forefront of energy innovation. Tapping into this potential will not only help us create a cleaner Thames for everyone but will also give us an additional supply of flexible, green energy which will help our transition to a decarbonised energy system.

“We’re thrilled to be leading the way.  We are looking forward to seeing how this approach could be scaled to other rivers across the country.”

Ferry, cross the Murky

Andy Hurley, director at Marine Zero, said: “Electric Thames isn’t just about achieving zero emissions on our capital’s river – it is even more exciting and significant than that.

“Along with our partners, we’re developing a completely new approach to increasing energy flexibility by developing new income streams new and flexible solutions for vessel and quay operators.

“We are delighted that Marine Zero has been selected to support the discovery phase of the project using our maritime experience and intelligence. We look forward to engaging with operators along the Thames over the coming weeks.”

His Falmouth-based company is developing what it believes is Britain’s first electric ferry, which charges by being plugged into a floating buoy.

Last year Marine Zero was awarded £3million by the Department for Transport to make a prototype electric-powered replacement for the St Mawes ferry in Cornwall.  The service  carries up to one million passengers a year.

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The £2million Renewables for Subsea Power (RSP) project connects the Blue X wave energy converter – built by Edinburgh company Mocean Energy – with a Halo underwater power storage system. The battery is the contribution of Verlume, an Aberdeen-based firm of specialists in intelligent energy management.

RSP’s final phase will begin in coming days. All equipment will be removed from the site, ahead of inspection onshore in Orkney and at Verlume’s operations base in Dyce, Aberdeen.

The cross-disciplinary trial, located three miles east of Orkney, sought to show how green technologies can combine to provide dependable, continuous low carbon power and communications to subsea equipment.  It offers a cost-effective future alternative to cables, whose drawbacks include are their long lead times and high upfront carbon footprint.

In recent months oil giants TotalEnergies and Shell Technology’s marine renewable programme have joined project leads Mocean Energy and Verlume in the pan-industry initiative. Also involved are Britain’s Net Zero Technology Centre, Thailand’s state fossil fuel extractor PTTEP, and four more partners.

 “The programme has been a tremendous success,” judges Andy Martin, Verlume’s chief commercial office.

“This phase was conceived as a four-month at-sea demonstration. But the quality of data and the robustness of our combined technologies led us to extend the programme. We now have increasing confidence in the reliability and the commercial potential of this system.”

From NZTC, Graeme Rogerson was just as enthusiastic: “It’s fantastic to see RSP successfully demonstrated.  It shows what’s possible when innovative technology is given the right financial and industry support.

“This is only the beginning for Mocean Energy’s Blue X wave energy converter and Verlume’s Halo underwater battery storage system; future phases will further accelerate the technology’s development and accelerate commercialisation, which is always the end goal.”

 After assessment, further uses may include repeating a second scheme in Scottish waters, or a venturing overseas. The prize is proving further how RSP’s combination of green technologies can enable reliable low carbon power and communications to subsea equipment.

In 2021, the consortium invested £1.6million into phase two of the programme – which saw the successful integration of the core technologies in an onshore test environment at Verlume’s operations facility in Aberdeen.

The same year Mocean Energy’s Blue X prototype underwent a programme of rigorous at-sea testing at the European Marine Energy Centre’s Scapa Flow test site in Orkney, where it generated first power and gathered key data on machine performance and operation.

Verlume’s subsea battery energy storage system, Halo, has been specifically designed for the harsh underwater environment, reducing operational emissions and facilitating the use of renewable energy by providing a reliable, uninterrupted power supply. Halo’s fundamental basis is its intelligent energy management system, Axonn, a fully integrated system which autonomously maximises available battery capacity in real time.

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One regional distribution operator, Northern Powergrid, has been accused of foot-dragging on a grid connection, after being unable to improve on a twelve-year wait to hook up one developer’s battery project.

Solar park builder Enviromena has taken the unusual step of issuing a public statement, accusing the DNO of “stifling” investment. The developer accuses Northern Powergrid of jeopardising the viability of its unbuilt farm at West Sleekburn, Northumberland.

Enviromena says its 30MW battery addition to the plant received planners’ approval in October 2022. But after talks, the DNO now can guarantee no grid connection date for the intended battery before October 2036.

According to the developer, Northern Powergrid indicated in discussions last year that its grid supply point at Blyth might enable an earlier connection, possibly available under the DNO’s Delegated Technical Limits programme.

The developer had hoped to confirm that earlier connection date before Christmas. But Northern Powergrid later told it that the Blyth hub had been removed from the DNO’s programme of accelerated connections, due to technical reasons. The developer says the grid company can commit to no alternative before the already stated deadline twelve years from now.

Enviromena CEO’s Chris Marsh said in a statement: “We are extremely disappointed with the latest delay, which has left a key project without a feasible connection date despite being ready to construct.

“The North East is enjoying a renaissance for clean energy as it emerges as a key hub for renewables, Marsh went on.

“The actions of Northern Powergrid go directly against the Government’s wider agenda to move away from fossil fuels and achieve carbon Net Zero goals by 2050 and it is stifling investment in the area. The delay represents a major setback.”

He added: “We submitted details to Northern Powergrid demonstrating our West Sleekburn project was ready for an earlier connection with both planning and land rights in place.

“The site is ready to provide much-needed storage facilities for cleaner energy. I would urge Northern Powergrid to re-focus their efforts on resolving the issues at Blyth and kickstarting accelerated connections in the area.

“We have seen other network operators across the country accelerate connection dates by as much as thirteen years in recent weeks and we hope a similar resolution can be found for the Sleekburn project.”.

Marsh cited the National Grid’s estimates that Britain will need over 25GW of battery storage, up from 1GW today, if it is to decarbonise the nation’s grid by 2035.

Reading-based Enviromena last month announced it was about to submit a total of 400MWp new unbuilt PV farm proposals for planners’ consideration, en route to an intended 500MWp goal next year.

Responding in a statement, Northern Powergrid confirmed the developer’s account.  The operator said it was working hard to bring forward connection dates for customers with schemes delayed by constraints on the transmission network owned and operated by National Grid.

The DNO commented: “Towards the end of last year, we announced that we would be issuing revised connections offers for some customers, made possible through a programme of delegated technical limits”.

“Customers looking to connect at a major substation at Blyth in Northumberland were included in the proposal for the first phase of this work.

“However, after further scrutiny by ourselves and National Grid, it will not be possible during this stage of the programme and so we’re re-evaluating what we can do to support customers looking to connect to this area of our network.

“We remain committed to working with our customers whose projects are impacted and to keeping them informed about the actions we are taking to accelerate grid connections in our region”.

This afternoon trade body SolarEnergyUK will present to MPs evidence of what it calls connection delays ‘descending into farce’.  Queues to connect to the grid, at both low and high voltage, now surpass 500GW, the group claims, citing a recent estimate by consultancy Roadnight Taylor.

Reforms such as the ‘Technical Limits’ programme, intended to deliver connections for big batteries and generating assets in advance of reinforcements to the transmission grid, would only be possible if output from the new supply assets was cut at source, DNOs have told Solar Energy UK said.

The most permissive limit seen by the body is 63%, in return for a connection date being brought forward by a year. In some cases, said the group, developers have been told that this limit is zero, with not a single solar-powered electron being allowed to flow.

Grid consultancy Novogrid has seen 50 such messages over the past three months, all with curtailment above 90%.

“You couldn’t make it up“, said SolarEnergy UK CEO Chris Hewett. “It is like being told you can open a shop on the High Street, as long as you keep the doors locked.

“This is bizarre behaviour“,  he added, “an apparent attempt by the DNOs to make it look like they are doing something while they still fail to invest in vital upgrades.”

Hewett will present this afternoon to the Commons’ environmental audit committee.  On the same topic also this afternoon, grid commissioner Nick Winser will answer MPs on the committee shadowing the D-ESNZ ministry.  Coverage begins at 14:00; click on the links to view a live TV feed.

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Located on a site 14km south-west of Inverness, the 450MW-rated Red John scheme will capture excess renewable energy, feeding it to grids as needed, and thus strengthening security of supply as Britain’s power network shifts from fossil fuels.  No price was disclosed for the buy.

Vendors ILI first conceived the water battery in 2015 and gained planning consent from Scotland’s government in June 2021.  Based in Hamilton, Lanarkshire, ILI claim a ‘robust’ 4.7GW portfolio of storage projects, both in pumped hydro and in electrochemical technologies.

Confirming its purchase Statkraft declared it demonstrated the enterprise’s commitment to helping Scotland meet its renewable energy targets and strengthening UK energy security.

A final investment decision is awaited. Stratkraft said the project will support ‘hundreds’ of jobs during construction and provide permanent local jobs once operational.

Founded more than 125 years ago, Statkraft is the largest producer of electricity from hydropower in Europe. It operates storage plants in both Norway and Germany, alongside over 350 other hydropower plants, including Rheidol, near Aberystwyth, in Wales.

From its UK head office in Glasgow, Statkraft envisages  at least £2bn of potential future capital investment in Scotland. Its UK assets include wind farms and the Keith Greener Grid Park in Moray. Besides hydropower and battery storage, its technologies of interest include grid stability and green hydrogen. Other projects in planning or under construction together represent.

Statkraft’s UK managing director Kevin O’Donovan said: “We are fully committed to supporting the UK in strengthening its energy security and helping to secure the economic benefits of the net zero transition. The acquisition of this significant pumped hydro storage scheme will play a key role in that.

But O’Donovan went on: “There needs to be an appropriate support mechanism in place, so we’re now looking to the UK government to provide the certainty that will allow us to proceed with confidence.”

Mark Wilson, CEO of ILI, also urged Westminster to provide policies supporting long duration storage.

“There is over 5GW of pumped storage hydro projects in the UK pipeline which will inject billions into the economy and create over 15,000 new jobs. We encourage the UK government to provide the support mechanisms now,” said Wilson.

ILI cites a 2021 study by independent researchers from Imperial College London. It found that just 4.5GW of new long duration pumped hydro storage with 90GWh of storage could save up to £690m per year in energy system costs by 2050, as the UK transitions to a net-zero carbon emission system.

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Victory in the tax battle coincides today with standards body the MCS confirming 2023 has again smashed records for solar PV installations.

Up to early December, the Microgeneration Certification Scheme logged 183,022 certified PV installations this year, beating 2022’s full total by one third. Now an estimated 2 million UK homes, plus thousands of commercial buildings, make subsidy-free clean power on their roofs.

After years of representations from industry body SolarEnergy UK, the government this week corrected its anomaly of charging householders 20% VAT on power storage devices retrofitted to homes.  New generating equipment had long attracted 5% VAT at most.

As many as a million homes with rooftop panels may have been put off installing batteries, say installers, when confronted by the VAT anomaly.

From next February, VAT will no longer apply to domestic BESS, ministers announced. The concession also covers water-source heat pumps and diverters, a technology that redirects excess power from solar or other renewables to a specific load or appliance, usually a water heater.

Despite the VAT wrinkle, battery installations at both initial and retrofit stages have grown wings this year.  Today’s MCS figures reveal a total 4,400 of the nation’s 4,700 MCS-certified BESS devices were installed in 2023, nearly 800 in November alone.

Numbers of contractors accredited by the MCS to intall storage devices have mushroomed this year, from 50 in January to over 850 now.

Heat pumps, insulation, draught-proofing and other energy-saving equipment for home use have been exempt from VAT since the chancellor’s 2022 Spring Statement. The exemption also extended to purchase of home-scale batteries or BESS when installed at the same time as generating panels.

Falling prices of new home-scale batteries have mirrored the earlier drop in price of domestic solar generation.  That has led more and more homeowners with panels to approach battery installers in quest of increased savings from the generation kit.

Another knock-on effect, say industry reps, has been slowing home owners’ uptake of batteries for use in time-shifting and flex exercises, brought in by suppliers to relieve grid stress by paying homes to cut their electricity consumption or shift it into overnight use.

In a debate on the Energy Prices Act 2022 last year, LibDem Lord Foster of Bath said: “With more efficient and cheaper batteries now available, it makes sense for those with older systems to add a battery. The solar energy their panels generate can be used far more efficiently to the benefit of the homeowner and the country overall. However, the 20% VAT rate is likely to deter many.”

Trade body SolarEnergyUK had long lobbied on the issue, and were dismayed it had not featured in Chancellor Hunt’s Autumn Statement last month.

Chris Hewett, chief executive of the SolarEnergy UK trade group welcomed this week’s victory

“Although a long time coming, this is great news for sustainable energy in the UK“, said Hewett.

“Installing a battery energy storage system can double the savings offered by a home solar installation, so with energy prices as they are, retrofitting one is a great decision,” he said.

Heat pump installs hit records

Today’s MCS data shows installations of heat pumps are at record peaks, as consumers hedge against continuing high bills from suppliers.

More than 35,000 installations of air source or ground/water source technologies were registered in 2023. This figure brought the UK to over 200,000 certified heat pump installations since 2008.

Heat pump uptake remained high in the second year of the Government’s Boiler Upgrade Scheme (BUS), launched in May 2022 to encourage households across England and Wales An initial £5,000 incentive to strip out boilers was this year upped to £7,500.

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Re-opening old mine shafts across the globe and extending the lives of those approaching closure are the focus of GraviStore, the Edinburgh firm’s proposal for rapidly dispatchable clean power, including potentially at grid scale.

Today’s deal commits the multinational giant to assist Gravitricity in developing its alternative to pumped hydro storage and to battery chemistries relying on lithium and other rare metals.

Employing ABB’s knowledge of hoist engineering in deep shafts worldwide holds out potential, the parties believe, to give purposeful second life to scores of thousands of existing, often declining facilities.

Unlike batteries relying on chemical storage, Gravitricity says its proprietary technology can assist power storage at various scales over many decades, and without any decline in performance.

The firm says it has already proven Gravitricity technically, thanks to a scale demonstrator in Leith. Now it is exploring the potential to deploy its groundbreaking technology in decommissioned mines worldwide.

ABB contributes unique depth of experience, says the Scots firm, thanks to its record of installing over 1,000 hoist and winches in deep shafts worldwide, including the example pictured.

Under the new deal, ABB will collaborate by providing research and development, product development and engineering teams specialising in the design, engineering and operations of mine hoists and mechanical, electrical and control technologies for hoisting.

Mine operators in Europe, India and Australia are already showing interest in Gravitricity’s offering, according to the firm’s co-founder Martin Wright.

“As the world generates more electricity from intermittent renewable energy sources, there is a growing need for technologies which can capture and store energy during periods of low demand and release it rapidly when required,” Wright noted.

“Our GraviStore underground gravity energy storage uses the force of gravity to offer some of the best characteristics of lithium-ion batteries and pumped hydro storage – at low cost, and without the need for any rare earth metals.

The Swiss-Swedish multinational sees its co-development with the Edinburgh start up as another route in working with companies providing adjacent and value-adding technologies.

“ABB has 130 years of history with mine hoists, since we first electrified one in Sweden in the 1890s”, said Charles Bennett, global service manager in ABB’s process industries division.

“Collaborating with Gravitricity shows how we can continue to diversify and adapt our technologies,” “We are eager to progress….as we become part of the next generation of renewable energy storage systems and to make use of mine shafts that are no longer in service.”

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The projects will both be located at greenfield sites, with one situated south of Glasgow at Cathkin, and the second at Broxburn, west of Edinburgh.

Construction is scheduled to begin before March, with both sites expected to be fully operational by April. Grid connection will be through SP Energy Network’s 33kV distribution network.

Both projects will help ENGIE towards its 10GW target of battery storage globally.

Aidan Connolly, head of battery storage UK at ENGIE, stated the utilities company was looking forward to working with Canadian Solar on the construction of the project, having signed two energy performance certificate (EPC) contracts for both 50MW/100MWh sites.

Canadian Solar’s e-Storage – previously CSI storage – is a subsidiary of the company’s manufacturing division. It launched its utility-scale energy storage product, SolBank in September 2022.

Renewable energy investor Copenhagen Infrastructure Partners (CIP), recently confirmed that SolBank will be the technology used for its 500MW/1,000MWh battery energy storage system (BESS) in Scotland.

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LiNA Energy, a privately held, six-year old spinoff from Lancaster University, has partnered with Turin-based Comau, a subisidiary of carmaking giant Stellantis, in evolving techniques to accelerate production of the cells, cheaper in their ingredients than lithium-based alternatives.

Focusing on the interface of ceramics and power storage, the British partners have emerged as pioneers in solid-state sodium batteries. But the enterprise realized they needed help in automating their production methods to secure lower cost output.

Engineers from both companies collaborated to design enclosure equipment for handling specific components of the solid-state battery cells.  Via trials in Comau’s cleanroom, they also came up with robot-enhanced solutions in identifying and integrating existing commercially available equipment.

Joint working enabled Comau to suggest improvements to LiNa’s manufacturing, resulting in optimised process dynamics as the Brits move to automated assembly of cells.

Advances in sodium-based battery cells are driving the deployment of a safe, sustainable energy source that can be used at high temperatures. Instead of completely replacing lithium-ion batteries, next-generation solid-state sodium batteries will provide high performance energy storage which is both cost efficient and can be optimised to integrate power from renewable sources, not least in high growth solar markets such as India.

“This automated manufacturing concept, designed with Comau’s engineering team, provides a clear technology roadmap to increase significantly production capacity of our patented battery cells,” said Kris Barr, LiNA’s operations director.

“After successfully researching process dynamics and finalised an innovative design proposal“, Barr went on, “we are looking forward to taking the next steps in our mission to commercialise our sustainable, low-cost solid-state sodium batteries.”

LiNA Energy says its sodium-metal-chloride solution is built around proven technology established on 1980s sodium chemistry, and refined with advances in modern materials science.  Sodium-based raw materials are abundant, adding to its batteries’ attractiveness to high volume manufacturers.

Offering greater safety, performance and sustainability in its devices, the UK company says it can commercialise them faster through shortened development lag time.

Comau’s expertise spans the value chain of battery production, from prototyping and pre-production to mass production and the recycling of end-of-life units. The company collaborates with the world’s leading electric vehicle manufacturers and actively participates in numerous projects promoted by the European Union for the development of e-Mobility technologies.

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Calculated by the ESO as six times the capacity of the Hinkley C nuclear plant, the ‘twenty gig’ offer is split 50:50 between already flagged regional distribution schemes, and higher-voltage transmission networks.   NG-ES says today’s announcement is in line with its five-point plan for hook-ups.

Over the Grid’s high-voltage transmission spine, 19 amp-hosting projects totalling around 10GW will be offered new dates to plug in, averaging four years earlier than current expectations.

The ESO’s removal of its insistence on non-essential checks before any battery is connected, a concession long sought by developers, enables today’s acceleration.

Over its lower-voltage distribution network spanning the Midlands, south west England and south Wales, an additional 10GW of unlocked capacity already announced will speed the process. The Grid portrays its initiative as bringing forward ‘shovel ready’ schemes by up to five years.

National Grid say it has talked to more than 200 projects interested in fast-tracking distribution hook-ups.  Sixteen say they want to plug in before late 2024, with another 180 looking to connect within two to five years.

The privatised NG-ESO is the monopoly which controls the contractual relationships governing the connection of new generation sites.

Prioritising shareholder pay-outs over essential upgrades to switches and cables is often cited by critics & clean power developers as causing waits of a decade or more to plug in new wind and solar farms.

Last month Common Wealth, a Labour-aligned think tank, reported that the privatised Grid had paid just short of £ 28 billion in dividends since privatisation in 1986. Achieving Net Zero by mid-century will require between £40 bn and £110 in network upgrade, they said with the costs likeliest to fall on customers or taxpayers.

The left-leaning analysts calculated that decarbonising Britain’s grid as expected by 2030 will require building five times the length of high-voltage backbone as were completed in the past thirty years.

Today’s acceleration will be delivered by National Grid Electricity Transmission (ET), the ESO’s arm charged with designing and building in England and Wales’ transmission infrastructure.

The passing into law two weeks ago of the 2023 Energy Act has also helped the initiative.  It will see the Grid’s duties as an ‘energy systems operator’ widened into its imminent replacement, a ‘future systems operator’.

ET president Alice Delahunty declared:  “We’re committed to speeding up connections and creating a ‘fit for the future’ process for plugging projects into the grid.

“Bringing these battery projects forward is one of a range of actions that our business is delivering to unlock clean energy capacity in England and Wales”.

NG-ESO chief engineer & head of networks Julian Leslie added:  “We’re pleased to see the tangible delivery against one of the key points of our five-point plan to speed up connections to the transmission grid for battery and storage projects.

“We’re evolving our network and taking the lead on speeding up connections to make our power system fit for the future, to deliver net zero and keep clean power flowing to the growing number of homes and business across Great Britain, fuelling our economy”.

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The national ESO’s distribution division provides DNO services in the Midlands, South West and South Wales. It has already attracted 433 homes with storage assets such as EV chargers or home-scale batteries to take part in this winter’s flexibility events.  Now it wants more.

“Flattening the spikes“ of peak demand is getting ever more valuable to operators of networks congested by ever heavier demands caused by increased electrification of heat, mobility and industry.

£147 million of network reinforcement upgrades deferred or mitigated was, grid operators calculate, the benefit of last year’s debuting of mass domestic load-shifting away from the most heavily contested hours.

As for last winter, flex providers will be rewarded over this winter, with the average participant company receiving £3,000 per MWh per year.   Depending on need, maximum earnings could rise to £18,000 per MWh, with some providers earning significantly more.

Preparing for last winter’s exercise, the Grid’s early calculations were to reward domestic accounts equipped with smart meters with payments as generous as 600 pence per kilowatt hour to cook, charge vehicles, or run storage heaters at times other than winter evenings.

In the late winter of 2022, around 100,000 Octopus Energy customers trialled load-shifting in collaboration with the Grid.

This year NGED’s system can be used alongside other flexibility products or supplier tariffs, aiding network operators’ quest to reduce customer energy bills.

Suppliers and aggregators looking to take part must be registered through National Grid’s Market Gateway platform.  This enables businesses to sign up to become Flexibility Service Providers (FSPs).

The online tool digitalises the process of procuring flexibility, speeding up interactions in the supply marketplace and simplifying the contracting process FSPs need to follow.

The distribution element makes up around 10% of an average customer’s annual bill equivalent, says National Grid to roughly £100, or 27p a day

Ben Godfrey, National Grid’s director overseeing distribution operations, said: “Stakeholder feedback over the last 18 months tells us that flexibility needs to be more accessible to a broader market.

“The Market Gateway is an online tool that reduces the burden of gaining a contract, registering assets and trading services. It standardises and digitises the commercial and technical registration processes, enabling a level playing field for suppliers, aggregators and marketplaces to develop flexibility markets on our behalf.”

National Grid assess its flex potential as over three million customers in areas where flexibility services are in operation. It plans to expand on past success with introduction this winter of Short Term flexibility procurement.

Helen Sawdon, NG’s commercial lead on flexibility, explained: “Short term trades will be procured on a weekly basis, with the availability and price agreed each week before delivery allowing opportunities for new flexible assets to enter the market as soon as they become eligible.

“We anticipate too that, by reducing the amount of time between procurement and delivery, we’ll see a greater level of successful participation from intermittent assets that are unable to commit to delivery over longer timescales.”

Among firms working with National Grid, Electric Miles, an EV smart charging platform, intends ensure that customers can benefit from offering themselves to flex.

Arun Anand, the firm’s founder & CEO observed, “Working with National Grid is a vital step towards achieving the UK’s green energy vision.

“The SmartFlex solution empowers EV drivers, charge point operators, and the grid itself. Users of the Electric Miles app play a pivotal role in EVs’ contribution to grid stability.”

Potential FSPs can register using the following link. More information is available at Flexible Power Website.

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From Turkish supplier Hydropower Engineering, RheEnergise will source the 500kW turbine and install it early next year at the Devon test site.

The device is a key component in RheEnergise’s proprietaryHD Hydro® system.

Designed to be dug into as many as 6,500 low UK hillsides, plus over 100,000 more in Europe alone, HD Hydro is – or so RheEnergise claim – scalable and more widely deployable than conventional pumped hydro, of the type that established at Engie’s Dinorwig’s 1.7GW ‘electric mountain’ in Snowdonia, or Drax Group’s 440MW ‘hollow mountain” at Cruachan in Bute & Argyll.

At times of low energy demand and thus cheap electricity, R-19, RheEnergise’s proprietory high-density fluid is pumped uphill between underground storage tanks sunk into a low hillside. As energy prices rise, the benign fluid is released downhill and passes through turbines, generating electricity to supply power to the grid.

RheEnergise says in theory it can offer generating stations as small as 10MW, from vertical elevations of 100m or lower, or 2.5 times less than conventional hydropower drops.

RheEnergise’s analysis of potential project opportunities has indicated that North America houses 345,000 potential locations, and half a million more across Africa & the Middle East.

The firm’s supplier Hydropower Engineering draws on Turkey’s successful experience with conventionally sized turbines. The country’s mountainous landscape and many rivers make it a natural home for hydroelectricity. Over 700 hydropower plants make up about 30% of the country’s electricity generating capacity.

Today’s deal with its Turkish turbine supplier follows RheEnergise’s agreement in August with British firm Mercia Power Response to examine the feasibility of getting 100MW of HD Hydro into commercial operation by 2030, utilising Mercia’s existing grid connections in the UK.

RheEnergise CEO & co-founder Stephen Crosher, pictured, heralded the turbine order as “an important milestone in our efforts to deliver our demonstrator project.

“The expansion of the long duration energy sector, and using new technologies like our HD Hydro storage system, is vital as the UK and other countries are placing a greater reliance on wind and solar to meet their future energy needs and to achieve Net Zero.”

Caglar Cinar of Hydropower Engineering (HPE) said: “We are excited to be given the opportunity to work with RheEnergise in a new and innovative part of the international hydro sector.  Given that their HD Hydro system can be deployed in many more locations than conventional forms of hydro, and quickly too, we see our turbine order from RheEnergise as a first of many”.

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Last winter the NG-ESO ran its first two batches of national trials for its DFS, designed to gauge how responsive home power users are – or could made to be – to messages that time-shifting will save them money.

As part of the experiment, the NG-ESO and participating suppliers advertised the cash advantages to homes who switched heavy usage devices such as washing machines to run overnight or outside times of peak power demand.

Results of the trials, as analysed on behalf of one battery vendor, were released this morning.  Kit retailer SolarEdge is heralding their insights as a ‘game changer’ in the promotion of home storage of electricity.

Unlike ‘manual turn-down’ participants, owners of SolarEdge’s Home Battery earned financial rewards for their stored battery power during peak hours, without having to reduce their electricity usage.

Consumption monitoring company Smart Metering Systems (SMS) used SolarEdge’s smart control technology to charge participants’ batteries remotely ahead of each DFS event and then maximize power export to the grid over the hours of the DFS event’s duration.

Autonomous control removed the need for homeowners possessing Solar Edge batteries to tweak the times when they ran high-consuming household devices.

The company’s analysis finds that participating battery owners earned up to ten times more financial rewards than participants paid by the DFS for manually tweaking – “time-shifting” – usage by big household appliances.

The highest financial reward received by a battery owner during a single DFS event was £25.60, against an average reward received of £6.52. In comparison, UK manual turn-down participants in the DFS trails received only £0.90 or so per DFS event on average.

In the six DFS events which SolarEdge batter owners participated in, the highest total reward achieved by a battery participant was £100.61. Projections by Smart Metering Systems suggest that if the DFS service becomes an enduring year-round service, domestic battery owners could earn over £300 per year.

The National Grid benefitted too from the DFS’ cuts in demand, through power flows re-scheduled to times when the grid could accommodate them.

Analysts found that participating battery-equipped homes were up to six times more effective in trimming back grid demand than UK homeowners manually twiddling appliances’ knobs. On average, battery-enabled participants exported 2.7 kWh to the grid per DFS event, compared to a reduction of 0.5 kWh or less posted by the average manual turn-down participant.

Mark Hamilton, managing director for FlexiGrid at analysts SMS, concluded: “Introducing automation into the DFS has game-changing potential to amplify significantly the volume of homeowner participation next winter and in future DFS events, and subsequently boost the impact of grid stabilization using home batteries.

“The ability to remotely schedule participants’ batteries to autonomously charge ahead of each DFS event and maximize power export to the grid”, said Hamilton, “means homeowners can earn passive income while consuming electricity as normal.

“This is in contrast to the DFS participants required to actively change their behaviour to earn energy bill savings. This was a key factor in the drop-off of participation we saw as the national DFS scheme went on.”

From home storage vendor SolarEdge, its Western Europe regional manager Amit Larom oberved: “We’ve seen first-hand the significant value battery-enabled flexibility response delivers to homeowners and grid operators alike.

“Home batteries enable homeowners to lower their energy bills and increase their savings by leveraging excess solar during evenings when electricity tariffs are at their highest.

“Participating in demand response programmes can further help improve the economics of purchasing a home battery”, said the SolarEdge salesperson.

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The automotive industry’s “sector bias” towards recycling risks overlooking other routes offering easier access to sustainability goals, say the British engineers.

Setting stiffer targets for recycling and waste collection, the new EU battery Directive seeks to embrace the whole battery lifecycle, from creation to disposal.   It mandates carbon footprint labels for batteries serving EV, light transport, and industrial markets, facilitating easier replacement for all. It even introduces digital “passports” for batteries, tracking them through construction, repeat sale and dismantling.

For various battery types it sets minimum levels of component recovery and content recycling, and against specific timeframes.

Autocraft’s experts welcome the initiative. But they say it downplays more environmentally-friendly alternatives such as repair and remanufacturing. Technology in those fields already exists and can be rapidly expanded, the UK firm believes.

Mike Hague-Morgan, Executive Director at Autocraft, commented: “We believe recycling is being prioritised too early in the EV battery lifecycle. Cells, modules, and packs are being sent for premature recycling, which usually involves incineration, before every last kilowatt-hour has been exhausted from them”.

Autocraft’s data highlights the inefficiency of current recycling processes, Hague-Morgan observed.

Endowing old EV power packs with second lives accounts for approximately 53% of the electricity required to produce a new one, 14% of the water and 59% of the associated CO2 emissions.

“Given its true impact, recycling is not the ‘green’ option people perceive it to be,” Hague-Morgan asserted

Eight years after the EU legislation has been enacted, it anticipates compulsory levels of recycled metals in batteries sold across the trading block’s 27 national markets as being 16% for cobalt, 85% for lead, 6% for lithium and 6% for nickel;

Five years later, by the mid 2030s, those required shares rise further, to 26% for cobalt, 85% for lead, 12% for lithium and 15% for nickel.

The Autocraft boss notes that, while the EU draft mandates that capacity of batteries should be  restored to ar least 90% of new, it describes remanufacturing as ‘an extreme case of re-use entailing the disassembly of any battery’s cells and modules.’

Hague-Morgan argues that battery remanufacturing is less of a burden than vehicle builders may believe. Autocraft already repairs and remanufactures thousands of battery packs every year for its OEM engine builders

Replacing a single battery module uses a tiny fraction of the electricity and water (3.2% and 2.8%, respectively) required to produce a virgin pack, while emitting a mere 2.9% of the amount of carbon and can be undertaken at regular intervals throughout the lifecycle.”

Autocraft’s boss said his firm’s remanufacturing supports their OEM clients in resolving warranty-linked problems, through dynamic testing and repair technology easily scaled up to meet market demands.

Awareness levels for remanufacturing remain low among vehicle makers, with misconceptions continuing to slow progress.

Hague-Morgan concluded: “Remanufacturing offers the most sustainable solution to extract all possible value from EV battery packs. Recycling is a valid option, but only once all avenues to repair and extend the life of each battery pack cell or module has been exhausted.

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Mercia’s 40 sites worldwide already have a capacity of 263MW; other are in development. Such scale offers an opportunity, the pair believe, to offer RheEnergise’s HD Hydro technology as a complementary, low carbon solution to its operating portfolio.

Expertise already possessed by Mercia PR’s industry partners in energy trading and forecasting could be an added benefit, helping RheEnergise optimise further forays into grid-connected storage.

In November, RheEnergise UK won a £8.25m small business research initiative (SBRI) contract from the government’s ££1 billion Net Zero Innovation Portfolio to construct a first-in-kind demonstrator rig near Plymouth.

At times of low energy demand from its clients, High-Density Hydro® works by pumping its proprietary High-Density Fluid R-19 uphill between interconnected underground tanks.

When power prices rise during the working day, the harmless fluid is released to power turbines for grid supply of electricity.

Working on height differences of 100m or less – see diagram- , a RheEnergise HD Hydro system requires only 40% of the vertical elevation needed for conventional hydro reserve, thus opening up far more of Britain’s – and of the world’s – hills and ridges for exploitation.

Operating thus under hills instead of under mountains, the system can provide power on tap where demand peaks at between 5MW to 100MW.

RheEnergise’s analysis of likely landscapes counts around 6,500 site opportunities in the UK, 115,000 in Europe, 345,000 in North America and 500,000 across Africa and the Middle East.

Mercia PR boss Graham White said: “It is very exciting to explore how we can engage with RheEnergise’s HD Hydro technology, applying our expertise in finding the right locations, developing sites, getting grid connections and operating within the Capacity Market.

“We see enormous potential for HD Hydro deployment as a future low-carbon alternative to our existing gas-powered assets.”

Stephen Crosher, White’s counterpart at RheEnergise said: “Mercia PR’s experience in flexible power response and its deep knowledge of the UK energy system will be hugely beneficial to the RheEnergise team.

“Our HD Hydro technology can provide medium and long duration energy storage, which is becoming increasingly important as the UK moves towards Net Zero and with a UK energy system that is increasingly reliant on intermittent renewables.

“We are delighted that Mercia PR has chosen to work with us.”

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