The large-scale digitalisation of the energy system, key for the delivery of a fit-for-purpose grid for net zero, is bringing with it new demands for cybersecurity, which must cover the whole value chain, from production and transmission to distribution and the consumer, including all the digital interfaces along this path.

As the number of connected resources grows – and they are rapidly with the fast-increasing uptake of distributed energy resources – so too do the number of interfaces and the number of involved parties. And with that the challenges to achieve a cyber secure system.

The EU’s new network code on cybersecurity, one of the 25 key deliverables of the energy system digitalisation action plan, is focussed primarily on the cross-border electricity flows that form a central component of the single market and was widely consulted in development.

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In its 60+ pages, it covers a breadth of topics, prefaced with a ‘General’ section covering such issues as the need for national competent authorities to carry out the tasks assigned in the regulation, cooperation between parties at national level, the important cooperation between ENTSO.E and the DSO Entity, which is at the heart of its implementation, and cooperation with ACER.

A key foundation for the network code is the establishment of a recurrent – every three years – process of cybersecurity risk assessments in the electricity sector at national and regional levels, aimed at systematically identifying the entities that perform digitalised processes with a critical or high impact in cross-border electricity flows and their cybersecurity risks, and then the necessary mitigating measures that are needed.

For that, the network code establishes a governance model that is aligned with existing mechanisms in EU legislation, such as the revised Network and Information Security Directive, with ENTSO.E and the DSO Entity required to propose the risk assessment methodologies.

‘High impact’ and ‘critical impact’

This notion of ‘high impact’ and ‘critical impact’ is fundamental and depends on the degree of impact of possible cyber attacks in an entity’s processes or operations, with those entities primarily those that have a direct impact on cross-border flows of electricity in the EU.

A second key component is the establishment of a common electricity cybersecurity framework with minimum and advanced controls respectively for ‘high impact’ and ‘critical impact’ entities.

Cybersecurity procurement and the broader supply chain are another key area, with recent cyber-attacks show that entities are increasingly becoming the target of supply chain attacks.

The TSOs are required to develop non-binding procurement recommendation for ICT products, services and processes – again differentiating whether the entity is deemed of high or critical impact.

Information flows and crisis management in the wake of a cyber attack also are crucial and the network code establishes rules around reporting and information sharing.

Finally, the regulation sets out rules for the undertaking every three years by critical impact entities – and on their request also critical service providers – of a cybersecurity exercise including one or more scenarios with cyber attacks affecting cross-border electricity flows directly or indirectly and related to the risks identified during the cybersecurity risk assessments.

The template for this is to be developed by ENTSO.E and the DSO Entity, with the involvement of ACER and ENISA.

Under the EU rules of procedure, the delegated act is subject to scrutiny by the EU co-legislators, i.e. the European Parliament and Council, each for 2 months with a possible 2-month extension.

Jonathan Spencer Jones

Specialist writer
Smart Energy International

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The loan will finance smart power grid development and expansion, facilitating the integration of renewable energy sources and new connections of clean tech assets, such as heat pumps and EVs.

The project will also boost industrialisation, economic growth and job creation in Spain, safeguarding 10,000 jobs a year in 12 autonomous communities during the implementation period. Additionally, more than 65% of the total investment will go to Spanish regions where per-capita income is below the EU average.

Of the loan, an initial €500 million ($542.7 million) tranche was signed in Madrid by EIB director general for European Union operations, Jean-Christophe Laloux, and Iberdrola finance, control and corporate development director José Sainz Armada.

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“Supporting power grid modernisation to facilitate the integration of new sources of renewable energy is among the priorities included in the EIB Climate Bank Roadmap,” said Laloux in a release.

“This new financing agreement signed with Iberdrola will accelerate Spain’s energy transition, ensure access to sustainable energy for all and contribute to the European Union’s strategic and energy independence.”

Added Armada: “This loan will enable us to speed up the decarbonisation of industry, a key process for Spanish companies.

“We will use this new EIB financing to expand smart grid development in Spain, as this is vital for facilitating the energy transition, boosting efficiency and improving the distribution network and supply quality. We will also contribute to the electrification of the economy and reducing the country’s energy dependence.”

The total investment under the smart grid project amounts to €1.44 billion ($1.6 billion), with the remaining €740 million ($803.2 million) provided by Iberdrola.

Iberdrola operates one of the largest electricity distribution systems in the world with over 1.3 million kilometres of power lines and more than 4,500 substations in Spain, the US, UK and Brazil, supplying electricity to over 35 million globally.

At the end of 2023, the company had green or sustainability-linked financing of more than €54.5 billion ($59.1 billion), including over €20.2 billion ($21.9 billion) of green bonds.

With this comes the risk that grid investments may be insufficient to deliver on the 2030 energy security and climate targets and need to be urgently addressed given the longer timescales of grid developments compared with clean technologies.

The analysis was based on the national grid development plans of 35 countries, including the EU-27, Norway, Switzerland, the UK and the Western Balkans.

Among the findings is that the grid plans of seven countries – Bulgaria, Greece, Ireland, Lithuania, Norway, Portugal, Romania – are based on lower wind and solar deployments than national targets, while those of a further six countries – Czechia, Denmark, France, Hungary, Luxembourg, Poland – are based on either lower wind or solar.

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Of these solar tends to be more affected, with its capacity underestimated by a total of 60GW across the 11 identified countries and wind by 27GW.

Conversely, in four countries – Croatia, Denmark, Finland, and the Netherlands – the plans are based on scenarios with higher capacities for wind and solar, ranging from 50% higher for Denmark to 200% higher for Finland and totalling 81GW.

Another finding is that in 19 out of 23 national grid plans examined, the deployment of solar expected under SolarPower Europe’s business-as-usual scenario is undershot by a total of 205GW by 2030, while in ten out of 31 plans wind is underestimated by a total of 17GW.

These discrepancies imply grid congestion may worsen in the short-term as grids are ill-equipped to manage the rapidly growing renewable fleet, the report states.

A third key finding is that spending on grids today in EU member states reaches approximately €63 billion ($68 billion), with an average of €28 billion per year earmarked for transmission grids and €35 billion invested in distribution grids in 2022.

This spending surpasses the European Commission’s REPowerEU estimate for annual grid investment of €58.4 billion until 2030 by at least €5 billion.

Furthermore, investment in national transmission systems will likely need to be augmented to make them ‘fit for purpose’ in those countries where the grid plans lag behind existing energy policy.

Commenting on the findings, Elisabeth Cremona, Energy & Climate Data Analyst at Ember, says there is no transition without transmission.

“We can’t afford to overlook grids. They risk holding Europe’s supercharged energy transition back if plans aren’t updated. Making sure solar and wind can actually connect to the system is as critical as the panels and turbines themselves.”

Expanding transmission grids capacity

Among other findings of the analysis is that European countries are planning to add over 25,000km of internal transmission lines between now and 2026. This corresponds to an increase of over 5% and would bring the total length to approximately 523,000km by the end of 2026.

Moreover, that accelerating network expansion is feasible is illustrated in the plans of ten TSOs. In particular, Energinet plans to expand its 7,440km grid by 3,300km by 2026, corresponding to an annual growth of 7.6% – over double the average growth since 2015.

Non-wires solutions – also known as ‘grid enhancing technologies’ in the US – in particular dynamic line rating and local flexibility also are being increasingly adopted by TSOs to increase the grid capacity as an alternative to new or upgraded infrastructure.

A further finding is the emergence of hydrogen in grid planning and the need for integrating both the demand and supply sides and coordination with the gas TSOs.

For example, strategic deployment of electrolyser plants could reduce bottlenecks in the electricity transmission grid and lower the need for grid expansion but is contingent on proximity to the existing natural gas network or planned hydrogen network.

Preparing the grid

To prepare the grid for the clean energy transition the report recommends political prioritisation of the grids, revision of regulatory frameworks to allow timely planning and investment and increased oversight and scrutiny of network plans along with enhanced reporting by TSOs on for example grid connection queues, available grid capacity and planned investments.

Placing clean power at the core of grid planning also would enable anticipatory investments.

The request, which was made by South Australia distributor SA Power Networks, energy supplier Alinta Energy and metering provider Intellihub, calls for the implementation of a framework for a universal deployment of smart meters to all customers by 2030.

In addition, it calls for the implementation of a range of measures to better support customers though this accelerated rollout, including improving the information provided to them and applying new consumer protections when they receive a smart meter.

The proposed rule change was made in a letter dated 22 September 2023 following the AEMC’s completion of its review of the regulatory framework for metering services and mirrors the recommendations therein, the letter states.

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The only material difference is that the rule change request does not include the AEMC’s recommendations in relation to customer access to real-time data, as it was unlikely the changes could be implemented by 1 July 2025 – the commencement date for the acceleration of deployment.

“We have jointly proposed this rule change request because we support the recommendations in the AEMC’s final report and consider that they should be progressed as a matter of urgency,” state the signatories in the letter.

As the AEMC is unable to self-initiate a rule change request, the intent is to enable it to commence the process, they write.

Other proposed changes include improving the meter installation process by reducing barriers to installing smart meters and enabling more efficient and coordinated deployments and implementing a new regulatory framework for metering businesses to provide power quality data from smart meters to the distribution network service providers.

This would enable these providers to improve the visibility of their low voltage networks, better integrate consumer energy resources and improve safety for customers.

The requirements for undertaking tests and inspections of meters to avoid unnecessary costs also should be clarified and improved.

Smart meters status

The proposed rule change is set to have the most impact in New South Wales, the Australian Capital Territory, Queensland and South Australia where, at the time of the AEMC’s report, the average smart meter uptake was around 30%.

Tasmania has a programme in place to accelerate smart meter deployment by 2026, while Victoria has already achieved a near-universal uptake of smart meters.

While the number of smart meter deployments has been increasing each year it needs to increase substantially more from a little over 400,000 units in FY23 to over 700,000 units per year from FY26 to meet the 2030 universal rollout.

The proposed rule change based on a draft determination due on 4 April is open to comment until 30 May. The AEMC then expects to complete the process by 11 July.

The battery, which will have a 500MW/2000MWh capacity, will be funded as part of the State Government’s commitment to expand battery storage throughout Western Australia (WA).

Collie-based earthworks and rehabilitation specialists Cardinal Contractors has been awarded the contract to complete site preparation earthworks for the battery facility, with up to 500 jobs expected to be created at the peak of construction.

The battery is expected to be completed by the end of 2025.

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Commented energy minister Reece Whitby in a release: “This is an exciting milestone for Western Australia’s decarbonisation journey.

“Synergy’s ground-breaking project is significant for the Collie community and will help local workers and families as Synergy seeks to exit coal-fired power by 2030.

“When complete, this battery will support reliability and more renewable energy on WA’s main electricity grid.”

Added Collie-Preston MLA Jodie Hanns: “The build of Australia’s biggest battery right here in Collie marks a significant point in the energy transition.

“Collie has been at the heart of WA’s energy system for decades and will continue to play an important role in the future.

“I’m delighted that a local business has been selected to be part of this project, creating local jobs as part of the ongoing support for our community by the Cook Labor government.”

Large-scale batteries provide long-term system stability to the power grid and support the uptake of more renewables, with Synergy planning to build 3GWh of storage by 2025.

The battery in Collie is the latest project coming from the company, with Kwinana Battery Stage One providing power to the South West Interconnected System since it was completed in May 2023.

Kwinana Battery Stage Two is under construction and is due to be completed in late 2024.

Originally published on Power Engineering International.

In an exclusive interview with Stuart Thompson, President of ABB Electrification Service and Antonio Martinez Reiner, Utilities ＆ Renewables Global Leader at ABB Electrification Service, we unpack circularity as a solution and what the barriers to digital adoption are.

Watch the full video interview below.

This interview was filmed in November 2023 at Enlit Europe in Paris, France.

ABB helps customers deploy proactive, predictive maintenance using real-time data analytics to monitor and evaluate asset health, reducing downtime, total cost of ownership, extending asset lifespan and preserving finite resources.

Read ABB’s latest whitepapers on how circularity and digitalisation improve sustainability and drive new levels of operational efficiency:

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• See the full potential of digital, faster – find ways to overcome your biggest IIoT barriers with this guide

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The 49MW/98MWh standalone project near Abernethy, Scotland, progressively came online from November 2023 as site sections were finalised, and was fully energised when construction was completed in early February 2024.

The Jamesfield battery system utilises 2-hour duration Tesla Megapack lithium-ion batteries, together with Tesla’s Autobidder AI software for real-time trading and control. Independent renewable energy company RES is the asset manager.

TagEnergy Chief Executive Officer Franck Woitiez said in a release that energisation of TagEnergy’s third battery energy storage facility in the UK was a testament to the momentum it has built in the UK as it speeds up the energy transition:

“This is another important marker for TagEnergy in the UK and beyond as we leverage our substantial storage expertise to help stabilise the grid and make a meaningful difference to the planet by relentlessly pursuing a renewables-led energy future.

“Our three completed projects, together with the more than 200MW of BESS under construction in the UK, is testament both to our commitment and the success of our approach.”

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The Jamesfield development became a joint venture with Harmony Energy, following TagEnergy’s acquisition of a 60% stake in the project in November 2021. Santander UK supported the green energy initiative with £12.5 million ($15.9 million) funding.

It was TagEnergy’s third investment in battery storage facilities in the UK to become operational, after Hawkers Hill Energy Park and Chapel Farm.

Those projects, together with other storage projects under construction, take TagEnergy’s secured portfolio in the UK to 320MW/640MWh.

Harmony Energy chief executive officer Peter Kavanagh added: “The completion of the Jamesfield BESS is another significant milestone for our valued partnership with TagEnergy, following the success of our other joint venture site, Chapel Farm.

“Battery energy storage systems are vital for unlocking the full potential of renewable energy in the UK. They play a pivotal role in advancing the Net Zero transition through the reduction of CO2 emissions and are crucial for securing the future stability of the UK’s energy supply and reducing dependence on foreign gas imports.”

The call follows the completion of ‘Project No Flow’ undertaken with the data collection provider Occutrace on the lifespan of non-household water meters, which found that the root cause of many non-consuming meters is the meter having surpassed its operational age and increasingly likely to fail.

In the project, supply point IDs with three or more meter reads showing no consumption were investigated, taken from a random sample of 2,000 supply point IDs.

Of these 771 meters identified as zero-consuming, almost two-thirds were found to be degraded to the extent of non-functionality.

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“Project No Flow has sought to establish hard facts and real-world evidence about meters that are not recording consumption to help the market understand the volume of potential zero consuming meters out there,” commented Claire Stanness, Metering Operations Manager at Wave and the project lead’.

“This first of its kind project has highlighted the issues that come with meters that are not recording consumption, issues that affect everyone.”

Along with the customers, who have to face the potential repercussions of inaccurate billing, retailers and wholesalers are also impacted with retailers having to correct and revise the bills and wholesalers seeing the impact inaccurate metering can have on the settlement process.

The study also found that many wholesalers do not have proactive replacement programmes in place for non-household meters, which would help to identify zero consuming meters and resolve the related issues sooner and thereby support the retailers in delivering reliable meter reads to their customers.

With accurate reads also comes the opportunity to identify any potential inefficiencies or cost savings for customers.

Wave suggests that to solve this issue a highly collaborative approach is needed, from the non-household water market operator MOSL, the regulator Ofwat, retailers, wholesalers, and their service providers, all working together towards a common goal of accurate and timely meter reads.

Wave also questions whether in the case of some properties being genuinely zero consuming because they were a flat above the shop or a secondary supply for the business, those meters should still be in the market or be disconnected.

The project report also suggests some potential areas that could form the basis for future metering committee or industry projects aimed at addressing issues inherent within the meter condition assessment space.

These include the introduction of a meter asset management programme and the replacement of broken meters with smart metering technology.

Specific market operational data quality weaknesses also could be tackled and new measures introduced for retailers identifying zero consuming assets.

At the outset of the project, MOSL data indicated that over 147,600 non-household water meters – approximately 11% – affecting over 113,270 occupied business premises across England were showing zero consumption.

The programme would allow PG&E to accelerate work on its electric system to further improve safety, reliability, capacity and infrastructure health, and to enable new interconnections to clean-energy projects that support decarbonization. Citizens has committed to contributing a large share of its profits from the programme to clean energy programmes in low-income and disadvantaged communities across PG&E’s service area.

If Citizens invests the full $1 billion, it expects the programme to generate hundreds of millions of dollars in charitable benefits over the lives of the leases. The programme is designed so that customers would pay no more for the applicable transmission assets than they would without the programme.

“At PG&E, we have a responsibility to build a better future for everyone whose lives we touch,” said PG&E Corporation CEO Patti Poppe. “We’re committed to finding innovative and affordable new ways to ensure that the transformation of California’s energy system benefits all the state’s residents. We’re excited and honored to partner with Citizens to help some of our most vulnerable communities build resilience against climate change.”

Citizens President Joseph P. Kennedy III said the programme will serve the nonprofit’s mission to support projects and programmes that increase grid strength and decrease electricity costs.

“Our vision is a safe, reliable and clean energy system that leaves no one behind,” Kennedy said. “This partnership with PG&E will advance our march toward a just and equitable clean-energy transition. We look forward to working closely with local communities in need across PG&E’s service area to hear their ideas about the investments that would most benefit them.”

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Programme details

Through the programme, PG&E may offer Citizens options to lease entitlements to PG&E electric transmission assets. PG&E may offer five separate leases of 30 years each, for a total investment of up to $1 billion.

Citizens would make an upfront payment to PG&E as prepaid rent.

Citizens would lease the rights through a wholly owned subsidiary that would be a CAISO participating transmission owner. Citizens would recover the costs of its investments through the CAISO high-voltage Transmission Access Charge, after Federal Energy Regulatory Commission (FERC) review and approval to ensure the costs are just and reasonable.

Citizens has committed to contributing 50% to start, increasing to 90%, of net after-tax profits from its investments in the programme.

Based on the terms of the programme, the transmission assets would remain under PG&E ownership and under the operational control of the California Independent System Operator (CAISO). PG&E would remain responsible for the development, design, permitting, engineering, procurement, construction and operations and maintenance of the relevant assets.

The programme needs the approval of the CPUC and FERC.  

Citizens investments

Pending regulatory approval, PG&E and Citizens expect to close on the first lease option in early 2025, with up to four more to follow through 2030.

Citizens will cap the capital cost component of its FERC rate at an estimate of the rate PG&E could have charged customers without the programme. Due to the size and structure of the programme, Citizens has also agreed to forgo recovery from CAISO customers of its own development and administrative and general costs, among other costs.

The CPUC and FERC have approved two similar programmes between Citizens and San Diego Gas & Electric (SDG&E) — the 117-mile (188.3km) Sunrise PowerLink transmission line, which connects SDG&E’s grid to renewable energy generated in the Imperial Valley; and the Sycamore-Penasquitos transmission line, which links two substations in San Diego via partially undergrounded lines.

A third project — an 18-mile (29km) upgrade to an Imperial Irrigation District transmission line that imports and exports power between California’s Imperial Valley and Arizona — is expected to be in service in spring 2024 and is expected to result in $18 million in charitable funds on a $40 million Citizens investment.

Citizens’ funds from those programmes supported the development of a 39-MW community solar programme to benefit 12,000 low-income customers of the Imperial Irrigation District.

Originally published on Power Grid.

The initiative, part of the Tennessee Tech University led smart grid modelling and testing ‘Smart Grid Deployment Consortium’ project in the Appalachian region of the US, will focus on creating AI-driven generative models for customer load data.

These will then form inputs to the modelling services of the HILLTOP microgrid simulation platform for modelling and testing new smart grid technologies, in particular for the rural electric utilities that serve much of the region and for example for energy tech startups that are interested in scalability and interoperability.

“This project is a powerful example of how generative AI can transform a sector – in this case, the energy sector,” says Kalyan Veeramachaneni, principal research scientist and principal investigator at the LIDS.

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“In order to be useful, generative AI technologies and their development have to be closely integrated with domain expertise. I am thrilled to be collaborating with experts in grid modelling, and working alongside them to integrate the latest and greatest from my research group and push the boundaries of these technologies.”

The generative models are expected to have far-reaching applications in that when trained on existing data, they can create additional, realistic data that can augment or replace limited datasets.

For example, in this case generated data can predict the potential load on the grid if an additional 1,000 households were to adopt solar technologies and how that load might change throughout the day

The initiative has been awarded $1.37 million in funding from the Appalachian Regional Commission and will include other participants from across Ohio, Pennsylvania, West Virginia and Tennessee.

Whenever I think back to 2023, one major sentiment that comes to mind is the urgent need for investment in Europe’s power grid system.

Interconnected renewables are coming online at a pace that the current grid infrastructure wasn’t built to withstand. And although the ramifications of this have started to show, investments seem to be able to bring relief.

Over the last week, this notion has been reinforced as some of Europe’s top utilities have released their financial results for the 2023 fiscal year.

The key takeaway, you ask?

Europe is finally investing heavily into its grid infrastructure with “record levels of investment” a phrase placed on repeat. The adage is sometimes followed either optimistically with “record investment plans” or more somberly with “it’s not enough.”

So, what does this tell us about the investment landscape within which grid business stands?

‘Plans’ are translating into action

Over the last week, utilities have released their financial results and laid out their investment plans for the coming years.

Germany’s 50Hertz is looking to invest €20.7 billion ($22.6 billion) in overhead power lines, on- and offshore cables, substations and other technologies, a three-quarter leapfrog compared to €4.8 billion ($5.2 billion) from the past half-decade.

E.ON is planning a €9 billion ($9.8 billion) increase to its 2024 to 2028 investment plan from €33 billion ($36 billion) to €42 billion ($46 billion), focusing on energy networks and energy infrastructure solutions.

And TenneT, which operates both in Germany and the Netherlands, is expecting to grow its investments to at least €10 billion annually.

Although very much welcomed, one tends to look towards ‘plans’ with a drizzle of scepticism. But what has been surprising is that these utilities and others are simultaneously announcing record investments in their 2023 results.

In Germany, E.ON invested €5.2 billion ($5.7 billion) in network expansion, modernisation, and digitalisation and 50Hertz invested €1.7 billion ($1.9 billion) in grid infrastructure.

TenneT invested €7.7 billion ($8.4 billion) between Germany and the Netherlands.

In the Netherlands, utilities Alliander, Stedin and Enexis each stated record levels of €1.4 billion ($1.6 billion), €1.214 billion ($1.327 billion) and €832 million ($909 million) respectively.

Penning an action plan and moving from paper to implementation are two very different challenges. It is encouraging to see this transition being made.

However, these statistics then beget a follow-up question:

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Is it enough?

In the Netherlands, it is not.

Alliander states that despite their record investments and upward plan, bottlenecks will be recurring on the power grid for at least the next decade. Even though this has been a repeated news item in recent years, it still warrants worry.

A case study to illustrate this is that of Dutch-owned TenneT, which has been mulling sale of its German operations to Germany’s Federal government for months now.

According to Handelsblatt reportage, the Federal Ministry of Economics is very interested in the German TenneT subsidiary, as the company is responsible for important north-south electricity highways.

The Netherlands, on the other hand, want to sell because they are afraid of the billions of euros in investments that will be needed over the coming decade to make the power grid fit for purpose.

Additionally, although TenneT reported healthy financial results for 2023, underlying revenues decreased for the utility by €600 million ($655 million), driven by a decline in ancillary service costs.

Said costs originate in lower market prices for costs incurred by TenneT to compensate for grid losses, maintain energy balance in the grid and pay for alternative electricity routes in case of congested or unavailable grid sections, as is the frequent case in the Netherlands.

Grid congestion and outstanding customer connection requests in the Netherlands, states TenneT, are being addressed through the National Grid Congestion Action Plan (LAN) and “unorthodox measures”, such as flexibility mechanisms, with which TenneT operates the grid at its limits.

Grid congestion has been hampering the utility not only in the Netherlands but also in Germany, where numerous bottlenecks in the grid on land cause large wind farms in the North Sea to be curtailed and redispatch limits the generation of offshore wind power.

This not only affects the amount of electricity fed into the grid, but also impacts its price development.

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What more do we need?

In its Electricity Grids and Secure Energy Transitions report, the IEA states that globally we need to add or replace 80 million kilometres of power grids. Global investments in grids, which has otherwise remained stagnant, now needs upwards of $600 million annually a year by 2030.

Additionally, citing data from 2021, the report finds that grid-related outages impacted the German economy by up to $3.6 billion, highlighting the role of the grid in minimising economic loss.

Illustrated by the cases of the Netherlands and Germany, Europe is clearly seeing its fair share of hurdles to be overcome, but positive signs can still be found if you know where to look.

Take for example the EU Grid Action Plan, which will improve access to finance for grid projects. The action plan is also expected to identify tailored financing models and increase visibility on opportunities for EU funding programmes for smart grids and distribution modernisation.

Although much more, both in terms of euros and cabled kilometres, is needed to reach a grid fit purpose, we can still be hopeful as plans are pushed into action.

How much are you investing into the grid now and do you think it will be enough to enable the energy transition? Let me know.

Cheers,
Yusuf Latief
Content Producer
Smart Energy International

Follow me on LinkedIn

The legislation, proposed by Peter Welch of Vermont and Angus King of Maine in the Senate and Kathy Castor of Florida, Paul Tonko of New York and Scott Peters of California in the House of Representatives, requires the Federal Energy Regulatory Commission (FERC) to establish a shared savings incentive for GETs to encourage their deployment by July 2025.

Instead of the traditional fixed rate of return on a capital investment, a shared savings incentive would return to the developer a portion of the savings attributable to the investment in a GETs, with some of the savings also going to customers.

Additionally, the proposed Act includes an annual reporting requirement that directs transmission owners to report the costs associated with congestion to FERC and directs FERC to analyse and make this data publicly available.

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It also charges the Department of Energy with creating an application guide for implementing GETs projects. providing technical assistance to stakeholders interested in GETs and managing a clearinghouse with examples of implemented GETs projects.

Senator Welch commented: “We’re at a crucial turning point in our work to achieve a clean energy transition, and meeting this moment requires new investments in clean energy technologies that strengthen the capacity of our transmission system.

“The Advancing GETs Act will motivate grid operators and developers to bring new projects online that expand transmission capacity by guaranteeing returns for these targeted, cost saving investments. This legislation will be crucial to boosting transmission capacity and helping the United States achieve its clean energy electricity goals.”

The introduction of the Act follows a week after Senators Welch and King and Representatives Castor and Tonko urged the FERC in a letter to implement a cost saving incentive for GETs – a proposal first made to the organisation in 2020 by the industry associations the WATT Coalition and Advanced Energy United.

Julia Selker, Executive Director of the WATT Coalition, said since that time no alternative proposals to incentivise utilities to deploy these technologies have been made.

“GETs do not fit well into today’s utility business model. By designing an incentive based on the system benefits of deployments, consumer value and protection is built into the regulation. This policy would drive innovation that has been stalled for years and start to unlock capacity and flexibility on the existing and future transmission grid.”

Some individual states have started acting on GETs. In Illinois and New York, for example, studies are underway to evaluate their potential and legislation is being advanced in Minnesota and Virginia among others.

Grid enhancing technologies are hardware and/or software that dynamically increase the capacity, efficiency, reliability or safety of the existing grid and include dynamic line rating, advanced power flow control and topology optimisation.

In February 2024 Cyprus’s Electricity Authority, the state-owned energy company, awarded the tender for the smart meter rollout to CyTA at a cost of €39.9 million (US$43.4 million), according to a report in the Cyprus Mail.

However, the award was challenged by one of the other two bidders, Logicom Solutions, which had put in the lowest bid at €33.6 million.

The third from New Cytech Business Solution was at €37.6 million.

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According to the Cyprus Mail report, Logicom argued that in awarding the bid, the Authority had violated essential terms of the tender.

However, the Tenders Review Authority upheld the Electricity Authority’s decision, basing its finding on reasons of public interest.

The decision is quoted as reading: “Any further delay in implementing the contract would raise the spectre of serious repercussions both for Cyprus and for EAC customers, via the loss of financing from the European Union, by no means a paltry sum…”

In presenting the case Giorgos Petrou, chairman of the board at the Electricity Authority, had suggested that delays could raise the risk of Cyprus losing funds designated in the EU’s Recovery and Resilience Facility.

For those, according to the Cyprus Mail, the deal with the meter supplier must be finalised by March 2024.

Moreover, the Electricity Authority must receive 50,000 smart meters of which 15,000 are installed by September 2024 and by June 2026 all 400,000 smart meters must be received with 250,000 installations completed.

According to an earlier Cyprus Mail report, the Electricity Authority had earmarked a total of €50 million for the smart meter replacements, of which €35 million would come from the Recovery and Resilience Facility.

The same report also indicated that the 400,000 smart meters would correspond to about two-thirds of the metered base, with some customers staying with their traditional meters for cost or practical reasons, such as the elderly who felt that they could not effectively be served with them.

This is not the first time the rollout has been delayed. In April 2022 the bid was awarded to New Cytech but was challenged by Ningbo.

Under a partnership agreement between the Swiss tech group and the Graal Group, more than 40 ABB fast and semi-fast chargers are being installed on Graal forecourts and service stations in five of Brazil’s major states: São Paulo, Minas Gerais, Rio de Janeiro, Santa Catarina and Rio Grande do Sul.

The ten fast and 31 semi-fast chargers will contribute to Brazil’s transition from a mobility network that is heavily dependent on fossil fuels to one that incorporates an EV charging network.

The collaboration will allow Rede Graal, a network of bus stations in Brazil, to offer EV drivers the convenience of ultra-fast charging, capable of replenishing a vehicle’s battery in less than 30 minutes, thanks to the same technology used in the ABB FIA Formula E World Championship.

Held at the Sambadrome in São Paulo, Brazil on Saturday, March 16, season 10 of the ABB FIA Formula E World Championship consists of an 11-turn, 2.93km circuit winding around the streets of the Anhembi district.

Luciano Nassif, country holding officer for ABB Brazil, said in a release: “Brazil, with its rich motorsport heritage, is a very fitting race location. It is also a country in which ABB has a strong history, having implemented technological solutions for more than 110 years and contributed to the development of diverse projects across industry and infrastructure throughout the country.

“The race here in São Paulo offers the ideal setting to showcase some of those projects across e-mobility, smart cities and energy solutions as we help drive progress in the race for the energy transition.”

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In Brazil, where renewables meet 45% of primary energy demand, ABB has also entered a power generation partnership with one of the largest wastewater companies in Latin America.

The company, which supplies approximately 30 million people in the region, has not yet been named. Smart Energy International has reached out for comment.

Under the partnership, Higra turbine and amphibious pump technology will provide solutions with high hydro-energy efficiency, ease of installation and low maintenance.

The project means the high water pressure created within the company’s pipes will be used to generate renewable energy, which can be distributed across the Brazilian network.

At the same time, ABB is providing fully integrated gas analysis systems for emissions monitoring to multiple customers in Brazil, including fertiliser and cement producers.

These systems provide a stable and precise analysis of the composition of gases emitted from production plants, helping users ensure environmental targets can be met.

Karman is built on a custom module that leverages the NVIDIA Jetson platform for AI in order to capture and analyse data to improve grid operations and manage distributed energy resources (DERs).

A first for the Karman platform, the integration should bring a new level of data insights to Aclara smart meter implementers, with up to a stated 100 times more processing power than traditional solutions.

Local AI models also will continuously learn to improve in areas such as grid planning, grid operations, load management, customer service and more.

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“As the grid becomes increasingly more complex and dynamic, utilities need more technology options to operate a clean and reliable grid,” comments Erik Christian, Division President, Grid Automation of Hubbell, of which Aclara is a division.

“By combining Utilidata’s extensive knowledge of distributed AI with Aclara’s decades of experience providing industry-leading hardware, we’re now able to bring new, innovative, interoperable solutions to our customers, starting with smart meters.”

A company statement reports that the partnership follows the trend of market momentum and federal funding driving the utility industry’s need to modernise and report its operational efficiencies, for which distributed AI holds vast potential.

In October 2023, the Department of Energy announced $3.5 billion in funding for grid modernisation projects, including awards to Portland General Electric, Duquesne Light Company and Commonwealth Edison Company to deploy over 100,000 Karman units to increase reliability and accelerate decarbonisation and electrification.

Elizabeth Cook, Vice President of Technical Strategy of the Association of Edison Illuminating Companies, said that utilities are seeking more options for new and innovative technologies, like distributed AI, for easily accessible and actionable data.

“Utilidata’s partnership with Aclara makes it easier for utilities to integrate this important technology as the industry continues to build a smart and adaptive grid that is resilient and reliable for customers.”

Josh Brumberger, CEO of Utilidata, points to a meter-embedded distributed AI platform as only a beginning.

“There are more opportunities beyond meters within the electric grid ecosystem that can benefit from having easy to access data and predictive analytics.”

These can be organised in two clusters in which concrete business cases/good practices should be developed, namely:

• investment, access to capital and the regulatory framework, including the need to enhance grid resilience, and
• build-out prerequisites including supply chain, staffing, permitting, etc.

Actions and concrete recommendations can then be generated for tackling by the next European Commission, which commences on 1 November 2024.

In a letter from the three organisations to the EC Executive VP for the Green Deal Maroš Šefčovič following their participation in a dialogue on Green Deal infrastructure, they reiterate the core role of DSOs in delivering on its objectives with most of the renewables being connected to the distribution grids and the increasing electrification of heating and mobility.

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Key messages they state include the need to accelerate investment by mobilising private sector capital for energy and improving funding opportunities for DSOs at the national and EU levels and in particular enabling anticipatory investments with a forward-looking energy regulatory framework and tariff regime.

Permitting procedures must be further simplified, especially for grid capacity additions and upgrades, and initiatives to tackle the supply chain challenge are called for, including greater cooperation between grid operators and manufacturers.

The focus on resilient grids also must be reinforced to guarantee the security of supply at times of increasing (cyber)security threats and extreme weather conditions.

Against this, general principles suggested for the future are:

• Ensure national implementation of the European provisions to provide grids with suitable conditions for the delivery of the Green Deal objectives.
• Introduce ‘grids mainstreaming’ to ensure that grid expansion is not lagging behind, but that their needs are considered in every new and revised energy and climate act.
• Ensure regulatory consistency by promoting widespread consistency in acts that help DSOs achieve their objectives.
• Build a successful EU Alliance for the Green Deal Infrastructure to prepare the infrastructure for 2050 climate neutrality.
• Combine all of the above into a strategic technical roadmap for the future that has the support of all stakeholders.

Given the short time horizon until the next European Commission and the need for two more dialogues to be organised by the time of the EC’s June election, fast action is needed, the organisations state in the letter.

With this short-term horizon, the focus should be on these most pressing topics and after each dialogue guiding principles and recommendations should be issued on the contents for each cluster that can be implemented within a timeframe and mechanisms for reporting established.

They also comment that the dialogues should involve all levels, European and national and should be complementary to other often more technical initiatives.

Announced alongside the Group’s full-year results, E.ON plans to boost its four-year investment plan from €33 billion ($36 billion) to €42 billion ($46 billion), focusing on energy networks and energy infrastructure solutions.

“Across Europe, there are massive expansion plans for renewable energy facilities that will need to be connected to networks,” said E.ON chief financial officer Marc Spieker in a release.

“Millions of heat pumps, residential electricity storage systems, and charging stations will need to be installed as well. That’s why we’re investing even more and even faster in our power grid infrastructure, which is set to continuously grow by an average of ten percent annually through 2028.”

Within the plan, €34 billion ($37 billion) will go towards E.ON’s energy network business, given a suitable regulatory environment. More than €25 billion ($27.3 billion) – 70% – of network investments will be made in Germany.

Approximately €5 billion ($5.5 billion) will be devoted to energy infrastructure solutions, E.ON’s growth business which provides solutions for industries, cities, and municipalities.

Other areas for investment include digitalisation projects, the rollout of smart meters and intelligent e-mobility charging solutions.

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Said CEO Leonhard Birnbaum during a press conference: “We again defied challenging circumstances in the financial year 2023. And we again delivered very good results that exceeded our expectations.

“This result is proof … that we increasingly benefit from our consistent strategic focus on energy networks and sustainable energy infrastructure and customer solutions.

E.ON investment: 2023 results

The Group significantly accelerated its investments in the financial year 2023, bringing it a total of €6.4 billion ($7 billion), a one-third increase from the year prior.

Specifically, the Group invested €5.2 billion ($5.7 billion) in network expansion, modernisation, and digitalisation and €1.1 billion ($1.2 billion) into customer solutions, of which approximately €700 million ($765 million) went toward its energy infrastructure solutions.

Energy networks delivered the largest share of Group earnings from 2023 with a €1.2 billion ($1.3 billion) year-over-year increase. Higher investments in E.ON’s growing network infrastructure were a key driver, ensuring increased connection rates for renewables, heat pumps and charging infrastructure.

In 2023, E.ON added more than half a million new connections to its distribution networks. Alongside higher investments, the recovery of the energy market environment had a positive impact on the network business. This led to a significant reduction in costs for redispatch in Germany.

Added Spieker: “E.ON looks back on a strong financial year 2023, in which we grew in almost all European markets. The outlook for the years ahead is very promising as well.

“Our network business is a growth business that is in the focus of attention for policymakers, the public and investors. Our energy networks are system-critical for the energy transition, and we’ve again proven that we can successfully and cost-efficiently expand them.”

In 2023, Tennet invested €7.7 billion ($8.4 billion), split between its operating areas in the Netherlands at €2.9 billion ($3.2 billion) and Germany at €4.8 billion ($5.2 billion). According to the TSO in its fiscal results for last year, this represents a sharp increase in investments due to on- and offshore grid expansion.

The TSO is now saying it will continue to increase its annual investments, while also mulling the sale of its German operations to state-owned investment and development bank KfW, on behalf of the state.

According to reportage in the German Handelsblatt, the state sale has been in negotiation between the federal and Dutch governments for months.

The TSO belongs to the Dutch state, although a large part of its grid operations are located in Germany and run by a TenneT-owned subsidiary, also named TenneT. The state negotiations concern the sale of said subsidiary.

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Flailing grid capacity

Although TenneT reports healthy financial results of €1.8 billion ($2 billion) in earnings before income and tax, up 50.2% year-over-year, over the course of 2023 underlying revenues decreased by €600 million ($655 million) to €9.2 billion ($10 billion), driven by a decline in ancillary service costs.

These costs come from lower market prices for costs incurred by TenneT to compensate for grid losses, maintain the energy balance in the grid and pay for alternative electricity routes in case of congested or unavailable grid sections.

In the Netherlands specifically, the power grid has continued to reach capacity, despite record investments from its operators last year. According to Alliander, traffic jams will recur on the Dutch electricity network for at least another 10 years.

In June 2023, the Dutch state provided €1.6 billion ($1.7 billion) to TenneT to cover the funding requirements of its Dutch operations.

Additionally, states TenneT, as there is no certainty of the German sale materialising in the short term, the Dutch state has also provided a bridge loan facility of €25 billion ($27.3 billion) in 2024, safeguarding TenneT’s planned investments in both countries for 2024 and 2025.

According to Handelsblatt, Tennet CFO Arina Freitag promised a sale within the next 12 months.

Said Freitag in a statement: “To achieve a futureproof energy system for a competitive and climate neutral economy halfway through this century, we must sustain investment momentum. Balancing economic efficiency, sustainability and a high level of grid availability expected by our end-customers in the Netherlands and Germany requires a massive grid expansion.

“For TenneT this adds up to an investment programme of as much as €160 billion ($174.8 billion) and requires a consistent energy policy and solution-orientation from all parties involved.”

The blueprint, which has been prepared by the Interoperability Network for the Energy Transition (int:net), is aimed to guide on transitioning the existing energy sector data infrastructures towards data space solutions and to define a general data space architecture that can enable an initial set of real-world business use cases.

In particular, the architecture is aimed at interconnecting the existing data infrastructures with federated data spaces, in which multiple datasets are mapped.

The concept of data spaces has been gathering momentum in various domains for sharing of data between multiple participants and the establishment of a common energy data space is one of the key actions set out in the EU’s energy sector digitalisation action plan.

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Foundational aspects that must be considered pertain to security and privacy, data quality and integrity and governance, while other aspects that need to be taken into account include the business model related to data exchange, legal and operational details and the technology, with a primary objective to ensure interoperability both internally and with other data spaces.

The blueprint document states that at the highest level, the CEEDS is foreseen as the common framework that federates different data spaces implemented at national, sub-national or international levels and allows the participation of single users.

Business use cases

The five representative business use cases, in which specific exchanges of data from diverse sources must occur among the involved actors, were defined as:

• Use case #1 – Collective self-consumption and optimised sharing for energy communities
• Use case #2 – Residential home energy management integrating distributed energy resources (DER) flexibility aggregation
• Use case #3 – TSO-DSO coordination for flexibility
• Use case #4 – Electromobility: services roaming, load forecasting and schedule planning
• Use case #5 – Renewables O&M optimisation and grid integration.

Based on these the proposed model corresponds to the creation of the energy data space as the combination of multiple ‘distributed data ecosystems’, i.e. the existing legacy data platforms, with an overarching layer defined as the ‘federated data space’ where the data is indexed and made discoverable and providing a ‘marketplace’ for sharing and possibly trading of data and data services.

Data space connector

The different data space participants are connected through a software component known as the ‘data space connector’, which realises the interconnection and data exchange.

This data space connector should be incorporated into the pre-existing platforms to enable identification, data harmonisation and brokerage towards data spaces, which can be useful for integrating data from different sources or for allowing multiple applications to access the same data without having to duplicate it in multiple places.

Moreover, in this model, the data space connector also enables the exchange of energy data and execution of services both among the existing legacy platforms and through the federated layer.

The document notes that to fully achieve the deployment of the CEEDS, starting from the federation of projects’ data space instances, detailed interoperability measures are necessary including technical interoperability, semantic interoperability and governance interoperability.

The document states that the presented blueprint underscores the critical need to adopt data space solutions within the energy domain, marking a pivotal moment for the transformation of the industry.

“The fundamental pillars of data spaces not only foster the active engagement of key stakeholders across the energy value chain but also promise mutual benefits, ranging from monetary compensations to an elevated quality of services.

“At this scope, the establishment of clear rules, policies and regulatory adaptations is a linchpin in facilitating fair data exchange, paving the way for an open market that fosters the participation of new actors, including data and service providers, as well as data consumers.”

The int:net initiative managed by the Fraunhofer FIT is an EU Horizon Europe-supported project to bring together stakeholders from across the European energy sector to jointly work on developing, testing and deploying interoperable energy services.

Key parties are the projects in the ‘energy data spaces cluster’, i.e. Omega-X, EDDIE, Enershare, Synergies and DATA CELLAR, whose findings have fed into the blueprint, while further inputs should come from the newly launched HEDGE-IoT, ODEON and TwinEU projects.

In the meantime, the blueprint will continue to be updated with version 2 due to be released in June 2024.

50Hertz, a Berlin-based system operator, announced their investment intention in response to the increasing amount of renewables coming online, resulting in increased demand for transmission capacity.

During a press conference, the operator said they integrated more renewables last year into the electricity than ever before. A total of 72% of electricity consumption across its grid area, they added, was met by renewables – the highest level ever – and now more transmission lines need to be reinforced or built to relieve grid congestion.

“50Hertz is entering a new phase in its corporate history. Its focus is shifting from planning and permitting to investment, construction and delivery. And we are making good progress in these areas”, said Stefan Kapferer, CEO of 50Hertz, at the TSO’s annual press conference in Berlin.

“We are preparing ourselves for the enormous efforts that will be needed well into the 2040s to make our transmission grid fit to meet the German and European climate protection targets. Faster grid extension and acceptance of the energy transition can only be achieved with greater cost efficiency.”

Commenting on the financial structure of the planned investment, Marco Nix, the utility’s chief financial and investment officer, said “Listed bonds remain the backbone of our capital structure.

“Around 60% of these relate to debt financing, like the two green bonds which amount to €1.5 billion ($1.6 billion), which we were recently able to successfully issue on the market. For the long-term success of the company, a solid development of equity and net result are also necessary.”

In 2023, 50Hertz invested €1.7 billion ($1.9 billion) in grid infrastructure and achieved an annual result of €220 million ($240 million) with equity strengthened by over 10% with shareholder support.

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Transmission buildout

Germany’s network development plan lays out transmission capacity needs, including 4,800km of new lines and reinforcement of 2,500km across the country.

50Hertz specifically, whose grid area covers the eastern German states as well as Berlin and Hamburg, has completed around one fourth of development measures for the onshore transmission grid, amounting to more than 800km of lines. Another 560km are currently being built.

This year, the company will also complete other important construction projects and commission a number of lines, including the Nordring Berlin project; the offshore grid connection for the Baltic Eagle wind farm (Ostwind 2); and the Uckermark Line, an important regional north-south connection between the Baltic Sea and the larger Berlin area.

In terms of offshore development, the plotting work for the Ostwind 3 project, which will connect the 300 MW Windanker wind farm to the mainland, has begun.

2024 also sees the company undertake preparatory work on line crossing under roads and railroad lines, including the SuedOstLink extra-high-voltage direct current transmission line between the Wolmirstedt and Isar substations near Landshut in Bavaria.

In future, 50Hertz’s on- and offshore grid is expected to grow by around 4,000km, provided that all projects included in the 2037/2045 Grid Development Plan were confirmed by the Federal Network Agency are included in the Federal Requirements Plan Act.

The new consultancy service draws on the energisation of more than 50 commercial grid connections and can work in any region of Great Britain.

With decarbonisation of the economy essential to meeting net zero targets, the country’s demand for electricity is forecast by National Grid to more than double by 2050.

Key infrastructure such as food manufacturing plants, electric transport hubs, residential and commercial construction and renewable energy projects that require a grid connection are often frustrated by complex and lengthy processes.

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For example, Ofgem data suggests over 40% of all applications for a grid connection for low-carbon energy schemes comprising over 120GW of clean power have been offered connection dates of 2030 or beyond, while around 20% would have to wait around 10 years.

Stewart Dawson, CEO of Vattenfall IDNO, says that the new Grid Connection Consultancy intends to provide an end-to-end solution for businesses.

“At Vattenfall IDNO, we recognise the urgency of achieving net zero goals and that many businesses find it challenging to manage the intricate process of securing grid connections. By offering a fully managed grid connections service, we aim to alleviate the burden for businesses that can’t manage this process themselves and accelerate the transition to a sustainable future.”

Historically, developers were obliged to connect via the DNO that controls the region in which the project is being built.

However, to introduce competition to help drive down costs, Ofgem has allowed independent DNOs to develop, operate and maintain local electricity distribution networks anywhere in Great Britain.

The Grid Connections Consultancy team includes electrical engineers, project managers, grid specialists and legal, regulatory and policy advisors.

Services offered by Vattenfall IDNO include power capacity and design requirement assessments, grid capacity reservation and negotiations with multiple landowners.

In addition, Vattenfall IDNO will carry out compliance audits for businesses looking to connect and can oversee on-site works.

To free up funds for those businesses, Vattenfall IDNO also offers a fee to adopt the new electricity network which can be re-invested by the developer.

The 44 projects, selected from 53 that were submitted for round three of the fund, will be led by energy network companies in partnership with innovators and partner organisations.

Priority challenges for eligibility included:

• Whole system planning and utilisation of networks, to facilitate faster and cheaper network transformation and asset rollout;
• Novel technical, process and market approaches to deliver an equitable and secure net zero power system;
• Unlocking energy system flexibility to accelerate the electrification of heat;
• Enabling power-to-gas (P2G) to provide system flexibility and energy network optimisation.

Project delivery

The SIF, funded by energy regulator Ofgem and delivered by Innovate UK, aims to find potential ideas for energy network challenges and identify those with the greatest promise as quickly as possible.

With their selection into the funding programme, the 44 projects will now enter their initial discovery phase. If successful, they will help customers and the wider electricity sector accelerate their net zero plans, build network resilience, access lower costs and streamline maintenance activities.

In a release, UK Research and Innovation (UKRI), which directs research and innovation funding in the UK, lists examples of selected network and flexibility projects:

Equiflex

Led by SP Energy Networks, Equiflex aims to promote equal access to flexibility markets, ensuring a just transition to net zero.

Equiflex project partners, Frazer-Nash Consulting Ltd, Energy Action Scotland and East Ayrshire Council, are looking at the design of flexibility options targeted at specific groups, such as less engaged and more vulnerable consumers.

They are also looking at the development of a toolkit to help stakeholders, such as local authorities, to evaluate which flexibility options might be best for their local context.

B-Linepack+

The B-Linepack+ project, led by National Gas, is exploring the feasibility of using geological solutions as intermediate scale storage.

The national gas transmission system can pack additional gas into the lines, known as linepacking. However, the amount of energy able to be stored by linepacking will decrease as we move toward decarbonisation of the networks with the use of hydrogen.

The project works with partners from the University of Edinburgh, Gravitricity Ltd, Southern Gas Networks, Revolutionary Engineering & Digital Design Ltd and Energy Reform Ltd.

It is looking at how lined rock shafts, engineered rock caverns and underground silos could provide purpose-built storage to supplement linepack capacity and provide system flexibility. This will enable supply and demand to be managed more effectively for consumers.

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UKPN flexibility projects

Additionally, UK Power Networks listed three projects selected for funding, including:

• Electric Thames: exploring the viability of electric-powered boats on the River Thames, and the possibility of boat power feeding the electricity grid to increase energy flexibility and reduce peak electricity demand
• KnowMyFlex: a proposal to create energy flexibility certificates, similar to energy performance certificate (or EPC) ratings, to show the existing and future flexibility potential of homes and buildings, helping customers engage with flexibility to reduce their bills
• WASH: an advanced study into the ways heat can be efficiently captured from wastewater and used to help district heat networks decarbonise

Luca Grella, head of innovation at UK Power Networks, said: “We’ve made remarkable strides during our first year with the SIF programme and are excited to be heading into a second with a new wave of projects which have exciting potential to make a real impact on both our communities and the way we work.

“This funding is allowing us to continue building strong bonds with some of the brightest minds in the sector. Our project collaborators play a key role in helping us deliver tangible benefits for our customers, and we can’t wait to reap the rewards of these partnerships.”

Launched in 2021, the UK‘s SIF fund is expected to invest £450 million ($577 million) by 2026.

As I was thinking about the content of this week’s tech talk, an article appeared in the popular press about a proposed plan to sheath the edge of the Thwaites glacier in Antarctica with a 100km long curtain to protect it from melting and potentially raising sea levels up to a suggested three metres.

The argument is that while a slow melt occurs as the warmer undersea current comes into contact with the edge of the glacier, as the climate warms so the undersea currents get warmer and the melting accelerates.

Moreover with that warming also the winter refreezing results in less ice recovery.

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Such geoengineering, or ‘engineering’ of the climate, is increasingly being talked about as scientists look for ways to slow or halt global warming.

Indeed, it is already being practised in the form of carbon capture from the atmosphere.

John Moore, professor of climate change at the University of Lapland’s Arctic Centre in Finland, is said to be on a mission to save the Thwaites glacier and quoted as expressing confidence the Antarctic Treaty countries will foot the $50 billion bill.

Cool Earth

So too is Yoram Rosen, director of the Asher Space Research Institute at the Technion Israel, who also has been in the news recently with a different type of geoengineering mission – in this case by placing a large shield out in space between the Sun and Earth to reduce the amount of solar radiation reaching the Earth.

The Institute, which claims to be developing a demonstrator in collaboration with the National Centre for Space and Science in the United Arab Emirates and the Israeli geospatial company ImageSat International, believes that a large-scale initiative has the potential to contribute significantly to the reduction of global warming by up to 1.5^oC.

The ‘Cool Earth’ proposal is to place the satellite at the first Lagrange point – a distance of about 1.5 million kilometres from the Earth towards the Sun where the gravitational forces of the two bodies cancel each other allowing a satellite there to remain in essentially a fixed position.

In practice, the satellite would exhibit a slight back-and-forth motion by controlling the shading sail, which also could be used to alter the amount of solar shading according to global climate needs.

“This ground-breaking project offers an original way to cope with the global climate crisis and perhaps even stop its destructive effects,” asserts the Institute’s website.

“Controlling the amount of energy that reaches the earth from the sun may even allow humanity in the future to directly control the desired climate over areas of interest on the earth and possibly prevent droughts and other climate-related natural disasters.”

The Asher researchers have estimated that to achieve the desired temperature reduction, the shade would need to be around 2.5 million km2 in extent – for perspective, in size between the areas of Saudi Arabia and Argentina.

The researchers haven’t stated when they expect the demonstrator to be ready to fly but there are numerous hurdles to be overcome before a large-scale initiative such as this – or any other large-scale geoengineering proposal – could be put into practice, not least the moral with the potential unknown side effect that could occur.

In a recent paper, modelling solar geoengineering – such as the Asher Institute proposal – and carbon dioxide removal, Moore of the Thwaites glacier proposal and the co-authors suggest that combined with the standard mitigation measures they could help to limit global warming.

However, they conclude more cautiously: “Scientific uncertainties surrounding the effectiveness, scalability, and long-term impacts of solar geoengineering and carbon dioxide removal techniques necessitate comprehensive research, rigorous modelling and robust international collaboration to mitigate the risks inherent in unintended consequences and to inform responsible decision-making.”

What are your views on solar geoengineering and should it pursued?

Jonathan Spencer Jones

Specialist writer
Smart Energy International

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The project, implemented as part of Enea Operator’s activities to modernise the energy infrastructure and introduce new solutions to improve the quality and security of supply, is aimed to contribute to improving the management of the distribution network.

Its basis is the use of proprietary deep learning algorithms from Polish software developer Affexy, with a focus on the most relevant data enabling continuous improvements that can improve the precision of forecasts and their adaptation to dynamically changing network conditions.

The project is predicated on the need to better adapt the grid to the changing conditions of the electricity market with growing renewable energies and for example new energy efficiency regulations.

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It is focused on three areas, of which the main one is the data analysis to enable understanding of the load on the network and identification of factors that affect the variability of that load.

Prior to that is the processing of the acquired data so that it can be efficiently analysed by the advanced AI models.

In the final step, a report and recommendations will be made with the conclusions from the analysis and suggestion of actions to optimise the data collection process and the quality of the forecasts.

Enea Operator anticipates that benefits will include a better understanding of the network load and the patterns that drive it – aspects that are critical for effective network management.

The project also introduces and pilots the advanced AI techniques, thereby testing the effectiveness of the algorithms in real-world conditions.

With the results and experience obtained, Enea Operator anticipates the implementation of a full-scale system.

Alongside this project, Enea Operator has concluded a PLN1 billion ($255 million) investment loan agreement with the European Investment Bank for distribution works.

These are to include the modernisation and construction of almost 8,000km of medium and low voltage grids, installation of 2.4 million smart meters, connections of 140,000 new customers, upgrading transformers by 633MVA and the connection of 4.3GW of new renewable generation capacity.

In a release, NatPower Group CEO Fabrizio Zago said the announcement marks the largest programme for the development of battery energy storage systems in the UK.

With a capacity of over 60GWh, the programme is expected to make up 15 to 20% of the UK’s battery energy storage system needs by 2024.

Specifically, NatPower UK – which is owned by Luxembourg-based global developer NatPower Group – has planned large-scale, nationwide development of battery energy storage systems.

Rollout will start with three ‘GigaParks’ to be licensed by later this year and another 10 by 2025.

Alongside the upcoming battery pipeline, the company announced the allocation of over £600 million ($770.6 million) towards developing substations to help speed up connections to the power grid.

Added to this are plans to develop large-scale solar and wind energy infrastructure, which will be announced with more detail by NatPower UK later this year.

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Commented Zago: “Today we present the largest programme for the development of battery energy storage systems, over 60GWh in the UK, and we are ready to collaborate with institutions and players in the sector to make the energy production system increasingly efficient”.

The more renewable energy fed into the distribution network from renewable sources, the more batteries are needed to store for use when there are peaks in energy consumption or when renewable sources are not available.

Said Stefano DM Sommadossi, CEO of NatPower UK: “To resolve the constraints that are slowing down investments in renewable energy, we will make investments in the energy distribution network, upgrading the substations for at least 15-20% of the new requirement.

“By investing in substations early on and focusing on energy storage systems, we will facilitate the next phase of the clean energy transition, thereby reducing the cost of energy for consumers.”

Added Sommadossi: “When it comes to resources, skills, policies, and investment, the UK is unrivalled and companies like NatpPower will help achieve the goal the country has set for itself.

Aiming to help keep the power grid reliable, the partnership includes direct integration with EnergyHub’s platform to enable Toyota and Lexus drivers to take advantage of utility programmes.

The programmes are designed to reduce the charging costs for EV customers while helping utilities ensure grid reliability and accelerate decarbonization.

Customers of utilities that partner with EnergyHub will be able to access several types of EV programmes, depending on what is available for their vehicles, including managed charging, vehicle-to-grid, EV-specific time-of-use rates, off-peak rebates and EV data programmes designed to support infrastructure planning.

This allows EV owners to unlock rebates to offset the price of installing eligible EV charging equipment and incentives for shifting charging based on system-wide and localised grid constraints.

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“Empowering our Toyota and Lexus EV customers with cost-effective energy solutions that reduce emissions and contribute to the grid underscores Toyota’s commitment to sustainable mobility,” said James George, general manager of EV Charging Solutions at Toyota. “Our collaboration with EnergyHub is an important step forward in enabling an exceptional customer experience within a home energy ecosystem.”

Shifting EV charging load away from times of peak electricity demand helps keep the grid reliable and can enable utilities to defer infrastructure investments that would otherwise be needed to meet increased demand for electricity as transportation electrification accelerates. This helps keep rates low for all customers.

Maryland-based Potomac Edison is the first EnergyHub utility client to enable customers to enroll Toyota and Lexus vehicles via EnergyHub’s platform and the platform is planning to expand participation into additional utility programmes later this year.

“Our collaboration with Toyota is a key milestone in EnergyHub’s effort to maximize customer choice through the largest ecosystem of EV OEM and electric vehicle supply equipment (EVSE) partners,” said Matt Johnson, VP of Business Development at EnergyHub.

“This integration accelerates our work to improve the overall EV ownership experience while unlocking grid service value for our utility clients.”

The five-year project included the deployment of 50,000 smart meters and the connection of Itron’s distribution intelligence (DI) enabled platform with Coopesantos RL’s customer information system.

With this upgrade with grid edge intelligence Coopesantos RL now has visibility and control across its diverse rural service territory, which includes mountainous and hard-to-access areas.

“Being the first cooperative to deploy smart meters in Costa Rica and Central America marks a significant step toward the modernisation of the infrastructure and distribution of electrical energy in rural areas where we provide service to all homes, businesses and industries,” said Mario Patricio Solis Solis, General Manager of Coopesantos RL.

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“Our electrical distribution deployment has been strengthened with this investment in technology and devices from Itron, automating and optimising our operational processes. We’re thrilled to continue working together as we embark on creating a reliable smart grid to prepare for the future.”

The solution was delivered via local Itron channel partners Conelectricas RL and Itecna.

Benefits anticipated by Coopesantos RL include more rapid insight and response to power outages with Costa Rica prone to extreme weather events, a reduced carbon footprint with reduced need for meter reading and increased client satisfaction with detailed insight into energy use and early detection of technical irregularities such as theft.

Coopesantos RL, headquartered in the city of San Marcos de Tarrazú, is one of four electric cooperatives in Costa Rica.

The cooperative claims 100% clean energy generation from two hydro plants, the 13MW Los Santos wind farm and growing distributed solar PV, primarily from commercial users.

In addition to energy generation and supply the cooperative offers fibre Internet services.

According to Alliander, traffic jams will recur on the Dutch electricity network for at least another 10 years.

Alliander, Enexis and Stedin, three distribution system operators in the Netherlands, each stated in their Q4 results record levels of investments into the power grid system in attempts to accommodate demand growth.

Alliander invested more than €1.4 billion ($1.6 billion) in 2023 on 2,207 transformers, 2,518km of new medium-voltage and low-voltage cables and 304km (2022: 255km) of gas pipelines.

Enexis spent €1.214 billion ($1.327 billion) on its grid, an increase of 18% from the year prior, installing approximately 1,350km of electricity cables and more stations.

Stedin invested €832 million ($909 million) in the expansion and maintenance of their grids, €120 million ($131 million) more (by over 17%) than the previous year, on 892km of power cables and 266 new transformer substations.

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A call to action

In 2023, states Alliander, it became clear how dire the situation is on the Netherlands‘ electricity grid; the network is under great pressure and has reached capacity multiple times during peak demand periods.

The company cites significant growth in clean tech assets, such as heat pumps, solar panels and e-boilers, as well as the electrification of business processes and installation of charging points for passenger transport and electric trucks, all of which continued in 2023.

This, alongside sustainable construction initiatives – making new and existing homes more sustainable by relying on clean technologies – will add heavy demand to the power grid.

Alliander also cites a shortage of technical staff, lengthy procedures, insufficient available space in the public environment and a lack of system choices that hinder further scaling up; to accelerate further where possible, stricter choices are needed.

Stedin, on the other end, calls on consumers, businesses and governments to jointly reduce the pressure on the power grid and make optimal use of renewable energy sources.

Said Koen Bogers, CEO of Stedin: “Stedin does everything within its capacity to expand the power grid…But that won’t be enough. Particularly in the evening peak, between 16:00 and 21:00, and on sunny spring and summer days, the grid is bursting at the seams.

“This is becoming a growing social problem. We ask consumers and businesses to adjust their behaviour and consider when they need a lot of electricity. For consumers, Stedin is launching an awareness campaign for this in March.

“After all, the moment you use power has become an important consideration. If we change our behaviour, grid operators can free up more capacity, which can then be used to connect businesses on the waiting list, as well as new-build homes and schools.”

In their statement, Enexis added that, despite the surges in demand and subsequent bottlenecks, Dutch businesses can still make use of the grid via flex contracts, interest in which has been increasing.

Through the contract, willing companies shift their production processes to the night, share electricity with a neighbouring company or instal batteries to make their business case possible.

Said Enexis CEO Rutger van der Leeuw: “We are also learning more about this every day and are developing new types of contracts to give customers a perspective for solutions.”

With opinions ranging from AI to electrification and renewables, as well as plays made by non-traditional entrants, this edition of Smart Energy’s Power Playbook lays down how experts analyse the evolving energy market.

Digital adaptation

According to Brad Johnson, director of solution management for tech company Bentley, a key talking point has been blending in automation, from AI – the core focus during the DISTRIBUTECH conference – to machine learning and augmented reality.

“One of the trends we’ve noticed professionals talking about is how to blend all these technologies into utility practices in a way that’s approachable for professionals.”

To do so, he adds, human assistance will be crucial as a “first step into automation. Rather than just pushing the button and trusting the output will match, it means keeping close supervision on the technology.

“AI and ML technologies will offer that ability to peer into the process, provide supervision and remove barriers to adoption.”

Hitachi Energy’s Steven Kunsman and Tanya Wright also highlighted this push into the digital environment.

Wright, a vice president of marketing and communications, comments on Hitachi’s moves to “transform itself as a global conglomerate and become more digital, because they see that the world is transforming and changing and moving toward digitalisation across all industries, including energy.”

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Referencing combined capabilities from Hitachi Energy, Hitachi Ventara (an IT services management company) and GlobalLogic (a digital engineering company acquired by Hitachi in 2021), the two reps comment that digital transformation has been a key thought in the mind of companies looking to grow.

Says Kunsman, head of global product management: “There’s competition and companies are looking to answer the question of (how to) position themselves…Utilities will be going through a huge transformation with their operational technology, including substations, where digitalisation and connectivity will lead this change.

“Increasing levels of renewables penetration and distributed energy resource (DER) plants are connecting to grids that traditionally were not designed for DER interconnection.

“For these changes, companies need to review their portfolio and solutions offering to identify gaps and develop strategies to either fill those gaps through various acquisitions or develop those capabilities within the organisation.”

Kunsman adds: “The biggest trend right now is the transition to clean energy and deployment of EV infrastructure. And from that perspective, every utility will have a role in this major transformation to be able to support this type of change in the marketplace.”

Electrification and the EV era

Kunsman’s commentary on digitalisation and EV interest came as no surprise. Utilities have increasingly recognised the increasing urgency of consumption management on the power grid as a high priority.

However, says Garret Fitzgerald of the Smart Electric Power Alliance (SEPA), although its importance is clear, this clarity is a recent phenomenon.

Fitzgerald, a senior director of research and industry strategy for transport and electrification, says that its importance only came onto the table over the last four to five years:

“I’ve been in this market for about 15 years and 10 years ago I started talking to utilities and advising them on the upcoming load growth from EVs and the subsequent planning that will be needed. But for five of those 10 years, most utilities said ‘It’s not a big deal. If they come, we’ll manage it.’”

Citing European policymaking and mandates for vehicle electrification, Fitzgerald says that signals are now being sent to OEMs to “invest billions and billions of dollars in battery manufacturing and EV lines.

“With all of that coming together at a global scale, utilities are recognising that the EV wave is here.

“When you see some of the sales figures for EVs – 25% in California and 10%, across the US – we see that it’s real.

“The biggest trend I’ve seen is that transition from three or four years ago of utilities being unsure of the EV transition to now acknowledging the need for load planning from their uptake and what this means for the distribution system and what it will require of regulators.”

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Renewable integration and non-traditional players

Of course, it is not only EVs that represent a significant load management challenge.

According to S&P Global analysis, clean energy technology investments in 2024 will rise by 10%-20% compared with 2023, with renewables continuing to take the lion’s share. This uptake was repeatedly cited as a key market focus.

“There is a much greater interest in integration of renewables than in the past and it’s growing all the time,” commented Phil Beecher, president and CEO of Wi-SUN Alliance, a California-based consortium of global corporations in the smart utility, smart city and IoT markets.

“Storage and EV charging continue to be areas of interest … However, we’re seeing huge growth in renewable activity in emerging countries, such as India and Latin America, where it seems to be taken very seriously.”

Echoing Beecher’s sentiments was Bryan Sacks, global CTO and solution leader for energy, environment and utilities at IBM, a tech company focusing on hybrid cloud and AI solutions.

“What I’m finding really interesting is non-traditional entrants into the energy market – for example, traditional oil and gas players – who are starting to invest heavily into technologies, such as batteries, EV charging stations and renewable generation.

“For example, we’ve started to see companies like Walmart, which has massive roof space for solar, looking at deploying this type of technology.”

According to Sacks, it is also worth watching how the energy market will evolve to take advantage of these new entrants.

“What impact is that going to have on the traditional energy regulated components of the marketplace that don’t necessarily have the same flexibility?

“The evolving interplay between the regulated market and other growth markets, as well as how utilities invest in non-regulated areas to take advantage of those spaces, will become fascinating to watch.”

Were you at DISTRIBUTECH International? What were your key takeaways and what are some of the most interesting trends you’ve seen emerging?

Let me know.

Cheers,
Yusuf Latief
Content Producer
Smart Energy International

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In 2023 the installed base of smart gas meters amounted to 55.9 million units and at a CAGR of 6.8% is projected to reach 77.6 million units by 2028, Berg Insight’s data indicates.

The annual shipment volumes amounted to 4.8 million units in 2023 and are expected to be around 5 to 5.8 million throughout the period.

The UK, Italy and Belgium were the most active markets, together accounting for the majority of the smart gas meter shipments during the year.

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While the rollouts in Italy, France and the Netherlands are largely completed, the UK market is ramping up yearly installations to reach a peak of around 3.3 million units per year during 2024–2025.

Belgium and Ireland also are expected to contribute with significant shipment volumes in the coming years. The Spanish market is expected to reach yearly shipment volumes of 1 million units by the end of the forecast period.

Smart gas meter networking

Berg Insight highlights how the smart gas meters deployed in Europe have been networked somewhat differently from the smart electricity meters.

A common model observed in the UK, the Netherlands and Belgium is to utilise a local wireless or wired interface to transmit gas data via the customer’s smart electricity meter.

A mix of 169MHz RF and 2G/3G cellular communications has been the primary model for the largest projects in which smart gas meters have been deployed independently of smart electricity meters, such as in Italy and France.

However, with the more ready availability of new types of LPWA technologies a shift in favour of these has begun.

Italy, for example, was the first to initiate large-scale adoption of NB-IoT as a primary smart meter connectivity choice and in 2023 the installed base of gas meters with NB-IoT connectivity in that country reached more than 2.5 million.

Berg Insight anticipates that by the end of the forecast period NB-IoT/LTE-M will become the go-to connectivity option for smart gas meters in several European markets, reaching an installed base of around 13.2 million units and accounting for as much as 60% of the annual shipment volumes.

The analyst also highlights the anticipated increase in the use of hydrogen in the European gas supply, with pilots underway in the UK and Italy with metering devices capable of measuring blend of hydrogen and natural gas or pure hydrogen and that interest in hydrogen meters is likely to increase as the technology matures.