The installations will start in the company’s southern communities and will lead to the installation of more than 260,000 of the new smart meters in the service area through 2025.

For Xcel Energy, the rollout marks the next step in the modernisation of its power grid, which so far has focussed primarily on boosting the capacity and reliability of the system through new and improved lines and substations.

With the smart meters, customers will be empowered to manage their energy use better while improving reliability and helping Xcel Energy restore power more quickly after an outage.

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“We’re excited to take this next step in building a smarter, more resilient and efficient energy grid and making it easier than ever for customers to understand and manage their energy use,” said Karl Hoesly, president, of Xcel Energy – Wisconsin.

“Smart meters are the starting point for this advanced grid, boosting reliability and providing new tools and technology to help customers lower costs.”

Smart meters will give customers near real-time energy use data with access through the company’s ‘My Account app’ or online.

They also will have access to programmes and services that will help them better understand their energy usage and how to improve efficiency and find more savings.

Currently, the majority of Xcel Energy’s old meters are AMR meters.

In addition to Wisconsin, Xcel Energy has smart meter rollouts underway in its service areas in Colorado, Minnesota and Texas.

The rollouts in North Dakota, South Dakota and New Mexico are tentatively scheduled to start in 2024 and in Michigan in 2025.

Xcel Energy serves approximately 3.7 million electricity and 2.1 million natural gas customers across the eight service territories.

The funding will be made available through concessional loans and equity investments to Western Australia (WA) through the Clean Energy Finance Corporation (CEFC) to new builds and major upgrades to transmission in the state’s major electricity grids.

Priority project in these grids, the South West Interconnected System (SWIS) and the North West Interconnected System (NWIS), were identified through WA’s demand assessment processes, with recent Australian Energy Market Operator (AEMO) modelling supporting the need for sustained investment in transmission infrastructure in the SWIS.

Upgrading the SWIS and NWIS networks

The SWIS is WA’s main electricity network and serves more than 1.1 million residential and business customers in Perth and across the South West. It starts north in Kalbarri, runs through Perth down to Albany in the south and extends to Kalgoorlie in the east.

The deal will finance priority projects across the SWIS to increase the supply of renewable energy and connect it into the grid by plugging in renewable generation hubs.

Initial modelling, states a release from the Australian Prime Minister, Anthony Albanese, suggests that in 20 years’ time, the SWIS grid will need to have up to five times more electricity than is available today as new industrial users connect to the grid.

The Pilbara’s NWIS consists of largely standalone networks owned by private companies and public entities with only a very small proportion (less than 2%) of electricity generated from renewables, adds the Minister’s office.

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The agreement will support more renewable energy in the NWIS, while ensuring existing infrastructure upgrades are coordinated between industries and governments.

Stated the Prime Minister: “Today we are joining forces with the Cook Government on a AU$3 billion landmark deal to deliver affordable cleaner energy to West Australians.

“Rewiring the Nation will help future proof WA’s energy supply, while also creating new jobs in energy, mining and manufacturing.”

Added Premier of Western Australia Roger Cook: “In WA we are delivering on our sensible and achievable plan to decarbonise our existing industries and create new clean energy industries as we transition to net zero, unlocking new projects while supporting new and ongoing local jobs.

“This significant package means we can accelerate the development of key energy transmission projects to facilitate decarbonisation, while also building on my Government’s climate action plan and initiatives already underway towards more secure, cleaner, reliable and affordable energy supplies.

An investment of this scale is expected to support around 1,800 construction jobs and unlock future projects across WA, helping to empower regional communities.

Namely, a new battery energy storage fund has been announced in the US, which will be used to establish multi-year offtake contracts for asset owners in Texas and California.

And in Europe, TenneT and Alliander have announced their H1 results, both citing the grid as a key investment theme.

Energy Storage Fund

Gridmatic, a US-based power marketer, has launched its first Energy Storage Fund.

They will use the $50 million fund to oversee the management of up to 500MW of battery capacity in the ERCOT (Electric Reliability Council of Texas) and CAISO (California Independent System Operator) markets.

The fund is divided into two tranches, with the initial one successfully completed through a $24.95 million investment from an energy investor.

Using the fund, Gridmatic will establish multi-year offtake contracts with asset owners to operate energy storage using its AI algorithms.

Gridmatic has already begun operating a 50MW/100MWh battery storage system in Texas using the fund.

Announcing the release, Gridmatic cites its ability to ensure secured revenue streams for developers’ projects through offtake agreements, enabling them to obtain necessary financing.

This, in turn, empowers storage developers to recycle their capital into the development of additional storage systems.

Gridmatic is then able to maximise the returns of the contracted storage systems via its AI-enabled optimisation, they state.

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The company references their storage report, showcasing a 46% increase in revenues when back-tested against actual results for storage systems in the ERCOT market in 2022.

“By decoupling project development and active management of the batteries, this structure derisks the operational phase of a project for storage owners and supports the growth of the energy storage industry,” states the company in a release.

The fund is also hoped to open a new asset class for investors, with the sector’s growth set to be further accelerated by the Inflation Reduction Act.

The fund is proof that new kinds of investment opportunities are on the rise as the battery energy storage market is maturing. This is fuelled by extreme market volatility due to the growth of renewables and extreme weather and an increased need for grid stability.

Grid investment driving H1 results

After the first six months of 2023, companies and utilities have been releasing their quarterly and half-yearly results to demonstrate their successes or disappointments.

H1 results from TenneT and Alliander in particular are of interest, as they show the allocation of funds into grid systems. TenneT has been heavily investing in the grid to ensure security of renewable supply in the wake of the war in Ukraine, while Alliander has been reinforcing power lines as the grid continues to falter.

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TenneT

In the first half of 2023, TenneT invested €3.5 billion ($3.9 billion) in grid expansion and replacement, almost double the investment they made for the same period last year.

The Dutch-German TSO’s underlying EBIT increased by €351 million ($387.5 million) to €930 million ($1 billion).

In announcing the results, TenneT is calling the first half of 2023 “marked by solutions and partnerships for the medium and long term economies of scale.”

TenneT’s ‘economies of scale’ is reference to completion of large and long-term framework agreements to develop high-voltage infrastructure, including framework contracts for 14 grid connection systems, each with 2GW capacity and valuing a total of more than €40 billion ($44.2 billion).

Stated TenneT CEO Manon van Beek: “The huge grid expansion and maintenance task we carry out for the energy transition does not take place overnight. With our hundreds of projects, both onshore and offshore, now and over the next two decades, we are realising the electricity system of the future with a clear end picture in mind: Target Grid 2045.

“Achieving economies of scale, innovating together with the market, international cooperation and timely and governmental supported long-term infrastructure planning are key in making a carbon-neutral energy system feasible and affordable for households, industries, suppliers and TenneT itself.”

Alliander

The first half of 2023 saw network company Alliander invest €60 million ($66.2 million) more into expanding and maintaining the gas and electricity network than in the same period last year.

However, despite the significant investment figure, the company has also stated how “it is impossible to keep up with the pace of the energy transition” calling on companies for flexible use of the electricity grid to relieve congestion pressure as the Netherlands continues to experience bottlenecks.

Alliander’s net result in the first half of 2023 amounted to €109 million ($120.3 million), €2 million ($2.2 million) higher than last year. Operating income for the first six months increased by €275 million ($303.6 million) to €1.37 billion ($1.51 billion).

However, total operating expenses increased by €258 million ($284.9 million) in the past six months, mainly due to higher costs for grid losses because of rising energy prices. Operating costs also rose due to rising purchasing costs at TenneT.

In the first half of 2023, 595 new transformer houses were built with 1,084km more cable laid than in the first half of 2022 (918km).

Are your investments plans guided by the need to expand and secure a reliable grid? Let me know.

Make sure to follow Smart Energy Finances Weekly for the latest in finance and investment news coming out of the energy industry.

Cheers,
Yusuf Latief
Content Producer
Smart Energy International

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This is according to the N.C. Clean Energy Technology Center (NCCETC’s)’s Q2 2023 Edition of The 50 States of Grid Modernization. The quarterly series provides insights on state regulatory and legislative discussions and actions on grid modernization, utility business model and rate reform, energy storage, microgrids and demand response. 

A total of 539 grid modernisation actions were taken during Q2 2023. California, Texas, Maine, New York, Massachusetts, Minnesota, and New Jersey took the greatest number of actions during the quarter, followed by Connecticut, North Carolina, and Michigan.

The report discusses three trends in grid modernisation actions taken in Q2 2023: (1) states and utilities moving forward on performance-based regulation; (2) growing interest in long-duration battery storage; and (3) utilities including storage capacity additions in integrated resource plans.

“Both legislators and regulators showed a continued interest in integrated resource planning (IRP). Policymakers in several states, including Nevada, Virginia, and Washington considered revisions to the IRP process,” said Emily Apadula, policy analyst at NCCETC. “Meanwhile, policymakers in North Carolina and Oregon considered including other required plans within the IRP itself.”

The report notes five of the top grid modernization actions of Q2 2023:

• The release of South Carolina’s energy market reform study
• Maryland lawmakers adopting an energy storage target
• Connecticut regulators approving a performance-based regulation framework
• Maine legislators initiating a distribution system operator design study; and
• The Louisiana Public Service Commission Staff proposing rules for utility grid resilience plans.

“This quarter, the potential prospects of a Southeast regional transmission organization (RTO) saw additional support thanks to a South Carolina study released earlier in the quarter recommending the state — and others in the region — develop a Southeast RTO; or join an existing RTO, among other potential reforms,” observed Justin Lindemann, Policy Analyst at NCCETC.

“This comes months before an early July federal court ruling this year vacated FERC approval of the Southeast Energy Exchange Market — a proposed regional platform to buy and sell power close to energy consumption, supported by utilities representing more than 36 million retail customers.”

Originally published by Sean Wolfe on Power Grid.

According to the Group’s 2023 ISG Provider Lens Power and Utilities – Services and Solutions report for Europe, European governments are seeking to blunt the impact of unprecedented energy inflation and utilities are stepping up investments in upgrading infrastructure.

“Utilities are under constant pressure to reduce operating costs and improve customer service,” said Ola Chowning, ISG partner, North Europe. “That is why many of them are turning to providers that offer digitally managed intelligent solutions.”

The growing shift toward clean energy is fundamentally changing the dynamics of the European power and utilities sector, ISG says, and in addition to pursuing self-reliance, the goals of achieving net-zero and decarbonisation are now driving investments in the sector.

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Specifically, states ISG’s report, the following trends are impacting Europe’s power and utility industry and its quest for self reliance:

Industry convergence

The need for sustainable energy sources and net-zero targets has started to blur the distinction between oil and gas or power and utilities industries. Oil and gas and power generation companies have begun moving toward becoming new energy companies through green and sustainable efforts like renewable and hydrogen projects.

‘Brown industries’ have started to invest in clean tech as utilities are moving away from being ‘only’ transmission and distribution companies or retailers. They are starting to invest in sustainable technologies like e-mobility or its related infrastructure needs, with decarbonisation a critical factor. Such industry convergence has led to unlocking newer revenue streams for these companies.

Aging infrastructure and rising costs

Many nuclear and thermal power generation units are nearing the end of their lifetime and require upgrading or replacement with new-age units. Compared to initial asset installation, the demand has also increased multi-fold, resulting in the maximizing the lifecycles of these assets and infrastructure.

Even first-generation sustainable power generation equipment such as wind and hydro turbines have almost reached the end of their lifecycle to be decommissioned. The current transmission and distribution infrastructure and its supporting grid infrastructure also face the challenge of needing an upgrade or replacement.

Given the current energy needs in the region, power generation companies and utilities are compelled to run the assets at maximum output, resulting in faster wear and tear of the infrastructure. The cost of replacing the entire asset at once is next to impossible, therefore power generation companies are incurring increased costs.

Asset resilience and rising operating costs

As noted, power generation companies and utilities are becoming more concerned about asset resilience.

Due to the age of these assets, there are increased possibilities of unplanned outages. The average load uncertainty due to volatility in hourly demand also creates possibilities for unplanned outages and sub-optimal asset performance.

This results in increased operational costs and an inability to meet the demand; therefore, asset resiliency services are much sought after so providers can maintain their current generation and distribution output.

Energy consumerism and customer expectations

The choice of selecting an energy supplier rests with the end customer. This has led to market reforms, linking the retail and the wholesale markets closer as consumers are provided access to information, especially on the costs and the source of energy generated, which is reaching the end customer.

The open market policy in Europe has brought competition onto the wholesale market to keep a check on pricing levels. Given environmental concerns, some customers prefer energy supply from a sustainable source, and some have even installed greener energy sources (solar PV) in their individual properties.

This trend has increased consumer expectations for an enhanced experience from the initial touchpoint.

Self-reliance for the future utility

Digital has been the buzzword for the future of the utility.

To address the above-observed trends and other business challenges, power and utility companies have started their digital transformation journeys by adapting new-age and next-generation technologies.

Digital transformation in the power and utilities sector would enable the move toward sustainable sources, increase asset performance and improve customer experiences while also meeting regulatory requirements.

However, writes Alan Greenshields, director of ESS Inc, as this transition accelerates it is broadly recognized that challenges associated with connecting wind, solar and battery technologies to the grid present significant impediments to achieving global climate and clean energy goals.

Understanding and overcoming these impediments will be critical if net zero targets are to be achieved. 

The energy epiphany

The war in Ukraine destabilised global energy markets and led to significant cost increases across Europe and worldwide, shocking the Western world into the realisation that the slow transition from fossil to renewable energy needs to accelerate significantly.

The epiphany has come with an understanding that this will require substantial investments in infrastructure as we transition the grid from big, centralised fossil power plants to distributed renewable infrastructure.

To deliver the transition, the US has passed the $370 billion Inflation Reduction Act, the EU is set to match the US with its Green Deal, and the UK has deployed a new Security Energy Strategy with promises to go further.

Beyond funding, a number of regulatory hurdles remain to realizing the potential benefits of these ambitious programs.

The UK strategy was announced in April 2022 and promised to slash through red tape so that solar, wind and battery infrastructure can be deployed and renewable goals met. One year later, reports by the Financial Times and others are documenting the ongoing challenges posed by interconnect issues, posing a significant barrier.

These issues have led to a queue for renewable deployments that can involve a 15 year wait in the UK to connect new renewable power projects to the grid. These delays pose severe headwinds to Britain’s ambitious decarbonization targets.

The challenge primarily lies in an outdated grid and an outdated bureaucracy. The UK’s National Grid, with its architecture designed for a small number of large fossil fuel generators, has historically had 40-50 applications for connections a year.

With the increase in new renewable projects, this has risen to about 400 a year, representing ~234GW of renewable energy waiting to be connected to the grid.

Grid infrastructure has not kept pace with the rapid growth in renewable projects. One way to accelerate renewable deployment while enabling grid upgrades will be to prioritize new projects that include long-duration energy storage (LDES) technologies. These projects can ease transmission congestion by storing excess energy during periods of over-generation and deploying it when needed.

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Overcoming the connection queue

Addressing a multifaceted problem will require multifaceted solutions.

First, clearly the bureaucracy that manages grid interconnections to evaluate and approve new applications needs reform to keep pace with the volume of requests.

A predominantly renewable grid will look different than the fossil-based system upon which we have relied to date, and our regulators must enable, not hinder, that transition.

In the short term, one potential reform that could accelerate approvals would be to prioritize project viability instead of simply “first come, first served” when evaluating proposed projects. This can lead to nonviable projects wasting limited public resources despite the fact that they are unlikely to ever be built at the expense of viable projects that could move forward quickly.

For example, the initial application doesn’t require a letter of authority for a parcel of land. Projects without a clear claim to a specific physical location can hold up projects on which construction could begin immediately.

Delays are worsened by other administrative issues, such as demands for cumbersome environmental assessments for each project, and the increasing cost of booking grid capacity in advance. In fact, a grid connection tied to a piece of land could be worth more than £1 million ($1.3 million).

The National Grid has addressed this issue in a recently published report saying it is carrying out “a major programme of reform to redesign the existing connection process”, which includes ensuring inactive projects are not blocking the pipeline.

Hopefully, this makes a positive impact, but we still need to go a step further to address the backlog. A good starting point would be to update the regulatory regime and remove planning blockers as well as changing to a first ready, first serviced basis and making sure that companies that put in applications have viable projects. 

Allowing greater flow of electricity

Transmission system upgrades are also needed to expand the capacity of existing high-voltage transmission lines to allow greater flows of renewable electricity, carry electricity long distances and better connect regions and communities. This will ensure people can access power when they need it, providing affordable and abundant clean energy.

In the long term, upgrades are likely to require more cables, poles, wires, and transformers to transport electricity, skilled workers, investment, and specific materials, all of which will be in high demand as many countries are facing the same challenges at the same time.

Grid reform

The UK can’t continue to react to one electricity/energy crisis at a time until the growing complexity of the grid and its reliance on fossil fuels brings it to breaking point.

Instead, the government must proactively put measures in place to ensure the grid can harness and accelerate the amount of renewable energy needed to meet climate targets.

Fortunately, grid issues can be mitigated in the short term by deploying new energy storage technologies to support the accelerated deployment of renewables.

Battery storage enables energy from renewables to be stored and then discharged when customers need power most, even if the wind is not blowing and the sun isn’t shining.  By integrating storage both into the grid and giving priority to those new renewable projects with storage components, it will be possible to improve the flexibility of the grid while also reducing emissions.

By re-examining not only the procedures for project approval, but the components that make up the grid, it will still be possible for the UK to meet our ambitious climate and energy goals, accelerate renewable deployment and avoid further reliance upon natural gas. We just need to get the rules right and allow ourselves to fully take advantage of new innovations that are commercially available today.

European Union funds will co-fund €135.8 million ($152.2 million).

In a statement issued by AST, the TSO’s board member Arnis Daugulis commented on how the funds are intended to drive fundamental changes needed across Latvia’s transmission network infrastructure.

“…by 2025 the Latvian transmission system will be fully prepared for the start of synchronous work with continental Europe. Disconnecting the Latvian electricity supply system from the network controlled by Russia and Belarus is a basic condition for ensuring Latvia’s energy independence,” stated Daugulis.

According to the Daugulis, the investment will also be used to install anti-emergency automatic equipment and improve “the commercial accounting of electricity for international connections and the dispatch management system.”

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€188.8 million ($211.7 million) will go towards the completion of the Baltic Synchronisation project, which will see the Baltic states synchronise with the European system, rather than that of Russia. The investment will be funnelled into completing the infrastructure and ICT aspects of the project, in line with the TSO’s plan for 2024 to 2033.

In the period until 2033, it is planned to invest €21 million (23.5 million) to €30 million ($33.6 million) annually in the reconstruction of 330kV and 110kV substations, lines and distribution points, ensuring the stable operation of the transmission system and the continuous supply of electricity to users.

In each project, AST has stated it will evaluate the wear and tear of infrastructure objects, verify their planned load and plan the development of the network in such a way as to prevent the transmission equipment from reaching its critical age in the long term.

The development plan of the Latvian transmission system also examines the dynamics of renewable energy power plant connections to the electricity transmission network, as well as perspective development projects on the shores of the Baltic Sea region.

This includes potential interconnections between Latvia-Sweden and the Baltic-Germany, which in the future could provide opportunities for the export of electricity produced in Latvia.

The ‘Eastern Green Link 2’ (EGL2) project will see the creation of a 525kV, 2GW high voltage direct current subsea transmission cable from Peterhead in Scotland to Drax in England.

The project is being hailed by the partners as “the UK’s single largest electricity transmission project ever.”

The subsea HVDC cable system is approximately 436km in length with new converter stations at either end to connect it to the existing transmission network infrastructure.

High-voltage direct current technology provides the most efficient and reliable means of transmitting large amounts of power over long distances subsea.

The EGL2 link will support the growth of new renewable electricity generation and help alleviate existing constraints on the electricity network.

The project is in response to the significant amount of new network infrastructure required for net zero in the UK, forming part of National Grid’s ambitious Great Grid Upgrade, announced earlier this year.

Commenting on the signing of the agreement, SSEN Transmission’s finance director Maz Alkirwi said: “Connecting the North of Scotland down to Northern England and transporting renewable power to communities across the country is crucial in delivering government targets for tackling climate change.

“It’s an important moment in a major investment in critical national infrastructure and we’re looking forward to working with National Grid on its delivery.

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National Grid’s president for UK strategic infrastructure Carl Trowell added: “Eastern Green Link 2 is part of our Great Grid Upgrade, the largest overhaul of the grid in generations. This new infrastructure will connect more clean, renewable energy from where it’s generated to where it’s needed, helping contribute to lower energy bills over the long-term and make the UK’s energy more self-sufficient.”

Work to progress the project will now be taken forward as a formal joint venture between SSEN Transmission and National Grid Electricity Transmission. Following final approval from Ofgem, work is expected to commence in 2024, with a targeted operational date of 2029.

The bipartisan Caucus, the initiative of Bob Latta, Republican representative for northwest and west central Ohio, and Marilyn Strickland, Democratic representative for western Washington, will run to the end of the current presidential term at the start of January 2025.

Its relaunch highlights the increasing focus on the grid for driving the energy transition forward.

According to a press statement, the Caucus will work to improve the security and reliability of the US electric grid by “increasing institutional understanding of grid complexities, identifying opportunities for productive and bipartisan engagement, and highlighting the constructive role technological innovation can play in bolstering grid infrastructure”.

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Latta said in the statement that ensuring the security and reliability of the electric grid cannot be overstated.

“From increasing efficiency to meet our growing energy needs to implementing modernised defences that protect against cyberattacks, there is much work to be done to safeguard this critical infrastructure.”

Strickland said in the statement that strengthening the nation’s energy grid “is necessary for a cleaner and more energy efficient future that supports good paying jobs, strengthens domestic power production, and decreases the frequency of power outages in our communities”.

“[I] look forward to highlighting the importance of an innovative, reliable and efficient grid.”

The Grid Innovation Caucus was first launched in 2014 by former representatives Renee Ellmers from North Carolina and Jerry McNerney from California as a forum for discussing solutions to the challenges facing the grid, with industry support from the National Electrical Manufacturers Association (NEMA) and GridWise Alliance.

Latta and McNerney then co-chaired the Grid Innovation Caucus for the 115th Congress, which ran from January 2017 to 2019.

Both organisations have welcomed the Caucus relaunch and have committed to working with it.

Debra Phillips, NEMA president and CEO, said: “Bipartisan commitment to a modernised and resilient electrical grid is an essential undertaking.”

Karen Wayland GridWise Alliance CEO, said: “No sector of our economy is transforming more rapidly than the electric grid, as new and innovative technologies compel changes to the ways we operate and manage the grid to provide reliable, secure, affordable and clean power.”

Christina Hayes, executive director of Americans for a Clean Energy Grid (ACEG), also commented, saying that strong, bipartisan solutions are needed to improve America’s transmission system.

“An expanded and modernised transmission system will lower consumer costs, prevent dangerous power outages and create good-paying jobs – all issues that cut across party lines.”

The Caucus relaunch also has been welcomed by Julia Selker, executive director of the WATT Coalition.

Highlighting the role of grid enhancing technologies in improving reliability and resilience, she said: “Transmission capacity expansion and grid modernisation are not keeping pace with the needs of American ratepayers and industry, and Congress can accelerate a digital transformation in the sector.”

The study, which was undertaken with Accenture, identifies three decarbonisation scenarios, or ‘speedways’, towards net zero by 2050 based on current policies – one on Fit for 55, another on REPowerEu and the third named ‘Radical action’ as an extension of the latter to deliver net zero by 2040.

Along with these are indicative targets across sectors for the interim 2030 and 2040 ‘landmark’ dates as well as for 2050.

With approximately 70% of Europe’s final energy demand in transport, buildings and industry relying on fossil fuels, these are considered the main target for decarbonisation, with the main route in the three scenarios relying heavily on electrification of demand.

Clean electricity is available via renewable energy sources, while efficiency gains lead to a reduction of the total energy needed.

Indirect electrification with e.g. hydrogen is favoured only in hard-to-abate sectors such as heavy industry and transport.

Among the three sectors, buildings see the largest absolute electricity demand, although the largest relative demand growth is in transport.

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Within this sector road and rail largely electrify towards 2050, while in marine and aviation, hydrogen is introduced as an alternative.

Similarly by 2050 light industries largely electrify, reaching rates of 74%, while hydrogen has the more important role in heavy industries, reaching 31%.

Overall the study finds that the share of electricity in final energy demand in 2050 should approach 70%, around 5,000TWh.

Power sector transformation

The study finds that all scenarios call for a strong increase in renewable capacities, with faster rollout of especially solar PV and onshore and offshore wind essential to meet the capacity demand.

The aggregated capacity amounting to an about ten-fold expansion for 2050 is estimated between 2,485GW and 3,287GW, requiring annual growth of over 80GW.

This, in turn, will require between 531TWh and 782TWh of flexibility by 2050 to balance the supply and demand, along with much-increased investment in both the grids and the generation capacity.

For example, grid investment is needed in the upper €30 billions per year by 2030 compared with the low to mid €20 billions in the latter part of the last decade, while generation investment needs to increase by about 50% to reach €80-100 billion per year.

Accelerated decarbonisation

Commenting on the study, Kristian Ruby, Secretary General of Eurelectric in an exclusive interview said that the study was aimed to provide insight into the EU’s accelerated decarbonisation ambition and a “first” to look in detail at the 2040 milestone and where the region needs to be then based on today’s policies.

“To be climate neutral by mid-century, 2040 is a natural milestone on the way,” he says, pointing to several reasons, including the discussions around carbon budgets becoming increasingly important and the implications for power sector investments after 2030 and whether these should continue essentially business-as-usual or there should be significant ramp-up, “which is what we are finding”.

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Key also is the opening of discussions by the EC on 2040 targets as a requirement for international reporting purposes.

Turning to the headline findings of the study, Ruby says there are three to highlight, with the first that it confirms that “electricity and electrification is an indispensable part of any credible and cost-efficient decarbonisation pathway”.

The second one is that with the implementation of all the technologies, there would be positive economic benefits for societies, but also for households.

And the third is that while “the target in the distance is important, it’s even more important to get going”.

“We have a lot of targets, a 2050 target and a 2030 target, but what we really need to do is start marching towards those and while we are happy to contribute to the debate, we need a period where we focus on delivering the already agreed policy.”

Scenario planning

While scenarios are not intended to be specific predictions of the future, they are nevertheless a key starting point for wider engagement and Ruby says that the Decarbonisation speedways study provides insights to inform discussions with the European Commission on the one hand and with industry stakeholders on the other.

They also do not take account of specific challenges that are faced, among which Ruby mentions those currently in Europe including the debate around electricity market reform, infrastructure permitting, supply chains and not least potential future skills shortages.

“In debates, everybody likes to give their two cents worth and what we’re doing is to basically say: What would be the implications? What are the things we should do? What should we build and where should we build – how many transformers, how many wind turbines? And what are the dollars and cents we need to invest to get this done? It’s about injecting some facts into the debate.”

This is according to Balance Power’s Are we developing the right electricity storage system (ESS) projects to help deliver net zero?, where the UK-based storage and peaker tech specialist company calls on government and energy industry stakeholders to shift gears in their ESS project pipelines.

At present, states Balance Power, projects are heavily weighted towards 2hr duration due to improved project returns.

However, 8hr duration projects provide the best balance between having sufficient operational flexibility to prevent excessive grid actions and minimising cost and time of connection through delivering more MWh capacity per connection.

Commenting on the report and its findings, Phil Thompson, CEO of Balance Power, stated: “With hindsight, the UK should have ensured that the technical needs of operating a net zero grid network and the business models driving the project development cycle are fully aligned, long before the projects developers are trying to connect were put forward.

“To lose this momentum due to the significant gridlocks we’re experiencing will have serious, long-term effects on our ability to reach and sustain a net zero grid.”

Readdressing the pipeline

To make this a reality and help reach net zero, Balance Power calls on the government to consider re-engineering business models and support mechanisms of longer-duration projects, which they state would commercially incentivise developers towards them as their designs of choice.

Not only will this address connectivity issues, adds Balance Power. It may also bypass the need for expensive upgrades such as extra transformers at connection points to allow additional power generation or storage connections.

Moreover, the company’s analysis highlights that the electricity storage marketplace is too orientated on the power [GW] of electricity storage projects rather than the growing importance of capacity [GWh].

In the industry’s infancy, power of electricity storage projects was more important as this was lacking, but with effective marketplace saturation of approximately 118GW connections, the marketplace requires reorientation to capacity to achieve the technical goals of operating a net-zero grid.

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To help facilitate this, the report states how industry stakeholders should explore the MWh/GWh approach and link all associated costs and revenues to this. In doing so, National Grid ESO and other stakeholders would be able to understand where the grid is in comparison with long-term capacity [GWh] targets, helping to drive targeted development.

Balance Power also observed that the requirement for dispatchable generation, which can be called upon on demand and is often fossil-fuel-fired, is the same independent of the electricity storage capacity [GWh] deployed.

According to the company, modelling from 2022 found two separate instances where demand exceeded net zero generation over multiple weeks, jeopardising security of supply if dispatchable generation was not available.

These cannot be simply treated as anomalies, they state. Future grid design needs to consider this issue by ensuring sufficient net zero compliant dispatchable generation is available, such as hydrogen, before existing dispatchable generation is decommissioned.

Nick Provost, commercial manager and author of the report says: “All stakeholders must ensure that the electricity storage business models and technical needs are aligned or we all risk losing out on a net zero grid system. Clean, dispatchable electricity generation technology investment is essential to avoid jeopardising our security of supply, and critically, our analysis suggests that facilitating 8hr duration electricity storage should be the goal.”

Against their report findings, and the estimated up to a 15-year wait for new energy projects, Balance Power is calling on regulatory bodies, such as Ofgem, and National Grid to review how they might incentivise the market to increase the duration of storage projects, thus helping to improve connection timeframes.

As innovations in artificial intelligence (AI) and machine learning (ML) continue to impact the smart grid, another technology is starting to play a pivotal role in enhancing powerline reliability: satellite-powered intelligence and ML algorithms to detect potential hazards.

By Dobrina Laleva, UP42

(R)Evolution of Satellite Technology

The technology revolution that has already transformed our day-to-day lives is also quietly transforming space. Satellites are no longer the huge constructions of the past – they have shrunk dramatically and are often no larger than a microwave. They also cost a fraction of what they used to and can be mass-produced. This has led to an explosion in data availability, coupled with advances in cloud computing and AI that enable the analysis of larger volumes of data.

In terms of numbers, there are more launches than ever, driving the cost per measurement further down. 2022, for example, saw 155 launches, 149 of which were successful. In 2022, 4,852 out of 8261 total satellites were active – an increase of 11.84% from 2021. 1030 of those satellites were used for Earth observation, second only to communications . Some of the many advances in satellite technology include the availability of very high resolution satellite data (think 0.3 m resolution), great revisit rates (multiple times a day), and a variety of images types available (infrared, multispectral, hyperspectral, SAR, and stereo imaging capabilities), among others. Satellite technology can also be used to strengthen the safety and security processes needed to keep power grids free from unpredictable faults and unwanted interference.

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Augmenting Utility Vegetation Management

From roads and railways to power lines and pipelines, encroaching vegetation causes downtime, damage and catastrophes.

Utility vegetation management remains a huge line item in most annual budgets, involving manual inspection of thousands of infrastructure miles. But it’s mainly reactive maintenance, leaving very little focus on prevention.

There are many factors to be considered when considering a new approach to vegetation management and definitively great benefits in adopting satellite technology.

First, it provides a unique opportunity to augment existing methods, offering more scalability, reliability and flexibility. Satellites can capture long corridor lengths in a single pass and do so frequently. This approach drives efficiency and savings and removes the constraints of LiDAR and UAV photogrammetry. Utility operators can identify risk areas for further investigation with helicopter optical imagery, LiDAR and UAV photogrammetry to avoid costly image capture of the entire infrastructure. Or they can task a satellite for a specific time and cloud coverage, which improves reliability and predictability, reducing risks from bad weather. Furthermore, using satellites for the most inaccessible points of infrastructure maximizes compliance and minimizes the risk of danger to employees.

Choosing the Right Data

Satellites offer different types of useful data: optical satellites, for example, take imagery in the visible or near-visible portion of the electromagnetic spectrum using existing radiation.

When optical satellites take imagery of the same point from two or three different locations, we combine those images to construct digital surface models, which are important for utility vegetation management.

Synthetic Aperture Radar (SAR) sensors, on the other hand, capture imagery by transmitting microwaves at a target and catching the backscattered signals at any time, day or night. SAR’s microwaves can penetrate clouds, haze and dust, as well as dense forest canopies to give information on different layers of vegetation. Elevation data can be used to track differences in elevation (height or volume) and ensure that hazards such as vegetation encroachment are monitored, predicted, and mitigated, minimizing damage.

While access to archive elevation data is great, it is mainly used to establish a base reference. This is because existing data may cover only some of the Areas of Interest (AOIs) needed for a project; terrain changes have occurred as a result of construction or natural events, or more precision and control are needed over the data used to produce elevation models.

In such cases, companies can task a satellite to get fresh stereo imagery. Stereo pairs (overlaying two images of the same area taken from different angles) or tri-stereo pairs (overlaying three images for even more information) provide an accurate solution for building elevation models.

Stereo images enable the generation of 3-dimensional models, and naturally, tri-stereo images create more accurate 3-dimensional models than basic stereo. Satellites can capture image pairs either in one pass, along the same orbit (along-track stereo), or from different orbits (across-track stereo). Stereo imagery can be used to extract stereo DEMs and DSMs. Stereo imagery can also be complemented with LiDAR, SAR and survey data to extract insights from different datasets and get a better overview in more densely vegetated areas.

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A Successful Story

A great example of rethinking vegetation management with satellites comes from an AI-first SaaS company, AiDash.

UP42, a geospatial developer platform and marketplace, helped AiDash transform the process for its customer, a Fortune 500 utility company that wanted to improve vegetation management along lines spanning over 80,000 km.

AiDash’s client relied on a traditional approach, with trimming cycles spaced across 4–5 years and manual data collection. This time-consuming process gave them minimal predictive capabilities for future outages, damages and costs.

To solve the problem, AiDash developed a proprietary AI model called the Intelligent Vegetation Management System (IVMS), with satellite imagery from UP42. Through the UP42 platform, AiDash accessed both archive and tasked very high resolution (50cm) Airbus Pléiades imagery of utility lines, providing detailed coverage for the customer’s remote asset monitoring needs.

AiDash was able to predict species’ growth rates and height levels compared to individual utility towers. The company prepared a 3- to 5-year trim plan for the entire network with an accuracy of over 85%, improving system reliability by 15% and reducing its annual budget for vegetation management by 20%.

There are countless more potential applications for utility vegetation management – from combining weather data with multispectral data to forecast strong winds affecting trees, to analyzing the state of surrounding forests for risk of fires.

With the recent emergence of dedicated geospatial platforms offering easy access to complex data, satellite imagery has proven to be the complementary tool of choice by many utility operators and solution developers, enabling more targeted and efficient solutions.

ABOUT THE AUTHOR

Dobrina Laleva is a senior product marketing manager at UP42 with over 10 years of experience in business development and product marketing for highly technical products.

At UP42, Dobrina leads full-cycle go-to-market strategies for new features, products, verticals and partnerships.

This is according to an analysis of the research organisation’s Utility investment in grid modernization report, which finds that grid modernisation investment has seen a 37% compound annual growth rate since 2012.

The largest emphasis, they state, has been on achieving higher efficiencies in the operation of the grid and protecting physical infrastructure from catastrophic weather.

Infrastructure hardening and AMI leading the way

Infrastructure hardening to protect against catastrophic weather, AMI and distributed automation represent 80% of current grid modernisation investment in the country, the report finds.

Investments in Distributed Energy Resources (DER) deployment and management are only at 2.4%, but, as most requests have been filed after 2021, they have the potential to surface as emerging modernisation solutions.

“Utilities are quoting DER integration and market enablement as the primary driver for their GM investments. When we compare DER-driven GM (Grid Modernisation) investments with the level of investment in DER management solutions, however, our data suggest that utilities are designing the grid to withstand the scale and variability of DERs rather than integrating more closely with them,” said Fahimeh Kazempour, head of grid modernisation for Wood Mackenzie.

According to the analysis, DERs are the primary driver for Advanced Distribution Management System (ADMS) expenditure, at almost $1 billion, which subsequently is creating a boost for Geographic Information System (GIS) investment as ADMS’s enabling technology.

The report notes that GM investment has grown with a 37% compound annual growth rate since 2012. The rate of growth is accelerating in recent years, with a 71% jump in investment from 2022 to 2023.

This acceleration will lead to 2024 seeing the highest level of annual investment by the studied investor-owned utilities, estimated at $5.9 billion.

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Regionality

Additionally, the report looks at how planned utility GM investments vary based on state and geographic needs.

The southeast has focused mainly on infrastructure hardening, as the region often deals with catastrophic weather events, such as hurricanes. The northeast has demonstrated elevated levels of investment in AMI, positioning it to implement advanced rates and shape prosumer behaviour.

Said Kazempour: “These investments depend a lot on each state’s policy or regulatory environment…An increasing number of regulators are allowing utilities to address their GM needs outside their rate cases.

“And when reliability and resilience concerns justify it, some regulators support controversial investments in capital-heavy infrastructure and utility ownership of DERs. What strategy a utility will take often depends on where they are located.”

The Wood Mackenzie report on grid modernisation was released earlier this week, drawing on critical data on utility strategies, initiatives, investments, deployed technologies and cost-recovery mechanisms, they state.

This financing will contribute to REN’s five-year electricity transmission investment programme (2022-2026) and is part of the wider REPowerEU Plan to boost green energy and support the EU’s autonomy and competitiveness.

A signature ceremony took place in Lisbon on Friday where the EIB Vice-President Ricardo Mourinho Félix and the CEO of REN Rodrigo Costa highlighted the significance of the €450 million.

Said Costa: “We are extremely pleased to have EIB supporting our commitment to the energy transition. REN is at the core of that movement and this green loan will help us to do more and better in an increasingly complex energy system.

“It will reinforce our investment capacity and will accelerate the development of new grid projects that will further enhance the use of renewable energy. These projects are part of a pan-European effort that is absolutely vital if we want to be successful addressing the climate change threats”.

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The project is expected to support the modernisation and efficient operation of the electricity transmission network in Portugal, increase its capacity, enable the connection and integration of new renewable energy sources (4.2GW in total additional capacity) and enable REN to maintain the reliability and quality of electricity supply.

This will include, among others, extension, refurbishment and modernisation of lines, substations and control and protection systems. Of the project, 10% is dedicated to improving the resilience of the network to climate change events, e.g. through reinforcement of towers and cables.

The programme is geographically dispersed throughout mainland Portugal, and it is expected that the majority of the investments will be in areas designated as EU cohesion regions.

Commented EIB’s Félix: “Resilient and efficient energy networks are critical for the economy and citizens of a country.

“Moreover, with this committed financing we are fostering the connection of additional generation capacity from renewable energy sources, thus facilitating the delivering of green energy to households and companies across the country.”

NRECA Research, the R&D arm of the National Rural Electric Cooperative Association (NRECA) applied for the smart grid development funding from President Biden’s Inflation Reduction Act for the Association’s 69 electric co-ops across 26 states.

If approved, the co-ops will use the funds to complete high-priority grid modernisation projects and increase the reliability and resilience of their electric power systems.

Specific co-op projects in the consortium application cover a range of technologies, including advanced analytics, distribution automation, unmanned aerial systems and second-generation AMI.

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NRECA Research’s consortium bid enables smaller co-ops to work together and submit a competitive application for infrastructure funds. According to the Association, it’s also the most effective way to ensure the funding benefits rural disadvantaged communities.

NRECA’s Research arm organised consortia to foster collaboration between co-ops and submit the competitive infrastructure funding applications. These consortia are organised around five topics:

• Electric vehicles
• Microgrids
• Cyber and physical security
• Natural hazards mitigation
• Smart grids and data

“Electric cooperatives are hubs of innovation and are always exploring new ways to meet their consumers’ evolving energy needs,” said NRECA CEO Jim Matheson. “This is an important opportunity for co-ops to partner with DOE to accelerate the adoption of new technologies to improve the resilience and affordable operation of the nation’s electric grid.”

The Hypergrid network, a grid modernisation project, is being touted by the TSO as one of the main features of their development plan.

The project will leverage HVDC (High Voltage Direct Current) transmission technologies to modernise existing power lines on the country’s east and west backbones, down to the South and the Islands, alongside new 500kV undersea connections.

In this way, the performance of these lines will be increased, their environmental impact reduced and more power generated by renewables in Southern Italy and transmitted towards high-load areas in the North.

Through the project, exchange capacity will double from the current 16GW to over 30GW. According to Terna, development of the direct current backbones will also minimise land use and environmental impact of their transmission grid.

Terna’s 2023 Development Plan

The €11 billion project constitutes more than half of the TSO’s energy transition budget in their Development Plan, totalling €21 billion ($22.3 billion) and consisting of four action plans:

• Increased exchange capacity between zones
• Infrastructure synergy
• Enabling renewables
• Grid resilience

The TSO is calling it their most ambitious plan yet, aiming over the next decade to accelerate the energy transition, promote decarbonisation across the country, reduce dependence on foreign supply sources and increase the environmental sustainability of the Italian electricity system.

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Over 30 projects are catered for by the plan and Terna will adopt a modular approach to develop a flexible investment model in the hopes of developing new grid infrastructure that reflects the actual energy scenario.

For this reason, planning and authorisation procedures for the new Hypergrid projects will be launched so that they can be implemented in line with system priorities.

The Plan was presented yesterday by CEO Stefano Donnarumma during a press conference with Chairwoman Valentina Bosetti, attended by Gilberto Pichetto Fratin, Minister of the Environment and Energy Security, and Stefano Besseghini, President of ARERA, the Italian Regulatory Authority for Energy, Networks and Environment.

Said Donnarumma, as quoted by Terna on Twitter: “The investments included in the 2023 Development Plan are the highest ever envisaged by Terna and will enable the energy transition and the achievement of the objectives that Europe and Italy have set for themselves in a decisive way”.

US Department of Agriculture (USDA) Secretary Tom Vilsack announced the investment to help expand and modernise the nation’s rural electric grid and increase grid security.

“These critical investments will benefit rural people and businesses in many ways for decades to come,” Vilsack said. “This funding will help rural cooperatives and utilities invest in changes that make our energy more efficient, more reliable and more affordable.”

The funding is being allocated across 64 projects through the Electric Loan Program for rural areas in Alabama, Arkansas, Colorado, Florida, Georgia, Iowa, Indiana, Kentucky, Michigan, Minnesota, Mississippi, Montana, Nebraska, New Mexico, North Carolina, North Dakota, Ohio, Oklahoma, Oregon, South Carolina, South Dakota, Tennessee, Texas, Virginia, Washington and Wisconsin.

The loans include $613 million to help rural utilities and cooperatives install and upgrade smart grid technologies.

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Nearly half of the awards will help finance infrastructure improvements in underserved communities.

The Electric Loan Program makes insured loans and loan guarantees to nonprofit and cooperative associations, public bodies and other utilities.

Insured loans primarily finance the construction of electric distribution facilities in rural areas. The guaranteed loan program has been expanded and is now available to finance generation, transmission and distribution facilities.

Local utilities also use the loans to invest in infrastructure to deliver affordable power to millions of residential, commercial and agricultural consumers.

In the coming months, USDA will announce additional energy infrastructure financing.

The Biden-Harris Administration’s Inflation Reduction Act provided more than $12 billion to USDA for loans and grants to expand clean energy and transform rural power production.

The partnership will see PGE make use of the NeXtworking platform from Expeto, which enables enterprise networking over private and public mobile networks, to accelerate grid modernisation and renewable energy outcomes.

The Expeto-enabled PGE private wireless network will support automated grid resiliency, monitoring of field conditions with smart sensors and devices, connected workers for enhanced employee safety and charging stations for Electric Vehicles (EVs) on the public grid.

PGE selected Expeto as a partner to provide next-gen connectivity based on successful deployment in the Connected Utility Lab, which confirmed the viability of PGE’s use cases over one year of extensive testing.

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Expeto’s virtual private network is based on connectivity from tier-one mobile operators. According to the company, their approach provides the scalability needed to support many grid nodes and devices necessary to achieve carbon reduction, resilience and safety goals.

The resulting network will eventually cover 4,000 square miles and connect 250,000 devices using existing cellular networks at one-tenth of the cost of traditional solutions, helping PGE avoid significant capital and operating expenditures related to a self-built private LTE network over the next 20 years.

“However, an enterprise deploys wireless networks for mission critical applications, they want the flexibility and agility to configure and manage it just like their existing IT network and from a multi-tenant, fully containerised platform,” said Expeto VP of product Brian Anderson.

“Expeto is the only software platform that enables an enterprise to deploy and manage mobile connectivity according to mission critical business needs…We are proud to support PGE’s leadership as they accelerate the transition to renewable energy.”

PGE’s mandated decarbonisation targets include an 80% decrease in greenhouse gas emissions associated with serving Oregon retail electricity consumers, compared to its baseline emissions by 2030​.

In the coming years, network operator Liander, a subsidiary of Alliander, will have to lay and replace 4,500km of new cables in these regions, and install around 1,600 transformer stations to ensure the grid – which to date has been experiencing bottlenecks – can be stable as more renewables come online.

In order to meet these requirements, Liander will outsource the work to a maximum of six contractors for a minimum contract term of six years. The contractors can register from now and the final ones chosen will be announced in June 2023.

In the tender, Liander asks contractors to help with the design and realisation of medium-voltage cables and the installation of new transformer houses. This also takes into account the living environment of residents, animals and vegetation. The activities of the contractors include earthworks (digging trenches) and laying and connecting electricity cables.

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One tender, two programmes

The activities in both regions are, according to Alliander, virtually identical. That is why they have been combined in one European tender. Because there are regional differences in the structure of the network, Liander will split the tender into two programmes after the final award.

The NuGelre programme focuses on Gelderland (excluding the Veluwe). The HELIX NHN programme focuses on Noord-Holland Noord: the part of the province that is located above the North Sea Canal, with the exception of Texel.

Both programmes are divided into three sub-areas (or lots) where the work will take place.

The work will start in September 2023 in the various sub-regions. The intention is to complete as much of the work as possible within the period 2023 – 2029.

Detection dog Jack, a springer spaniel, had a 100% success rate at a recent visit to one of the operator’s sites, where an artificial fault had been created to test the dog’s abilities, finding the location under asphalt on the first attempt.

The canine also used his nose to point to another fault it hadn’t been expected to find.

The pilot is continuing and forms part of a wider arsenal against the worst the weather can throw at the network this Winter. This includes the use of the UK’s first Low Voltage Support Rooms as well as drones and LIDAR-equipped helicopters to coordinate powerline maintenance.

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An arsenal of works

In a UK first, SP Energy Networks’ LV (Low Voltage) Support Rooms are using advanced monitoring technology to provide real-time information on supplies across their operating areas.

Data from smart meters and electricity substations are analysed to highlight where a potential fault might occur on the network, helping engineers find exact locations where repairs are required, sometimes before power drops and customers are aware of an issue.

These resources were set up as a permanent part of their operations following a trial that identified 30 ‘pre-faults’, saving an estimated £60,000 ($72,680) in equipment damage, stopping power cuts and reducing the amount of time customers were without electricity during repairs.

The operator also coordinated inspections of poles and wires that transport electricity around the country, using drones to identify areas of maintenance and helicopters equipped with LIDAR laser technology that scans whether trees have grown too close to power lines.

Scott Mathieson, SP Energy Networks network planning and regulation director, said: “Our teams prepare for winter weather all year round and we’re working hard to be ‘storm ready’ for the months ahead.

“It’s important we explore every avenue to either prevent the unplanned outages weather can bring or to make sure that, if they do occur, we can restore power to people’s homes and businesses as quickly and as safely as possible.”

SP Energy Networks is responsible for 105,000km of network and 30,000 substations.

Funded by the President’s Bipartisan Infrastructure Law, the Grid Resilience Innovative Partnership (GRIP) programme and the Transmission Facilitation Program together represent the largest single direct federal investment in critical transmission and distribution infrastructure.

It is also touted as one of the first down payments on an over $20 billion investment under the Administration’s Building a Better Grid Initiative.

These federal investments will unlock billions of dollars of state and private sector capital to build transformative projects that increase the reliability of the power grid and modernise it to drive access to affordable, reliable, clean electricity.

“We are moving swiftly to deliver cleaner, cheaper energy to every American community by building a modern and reliable electric grid,” said US Secretary of Energy Jennifer M. Granholm. “With nearly 70% of the nation’s grid more than 25 years old, the President’s agenda is making historic investments that will strengthen the nation’s transmission grid to drive down energy costs, generate good-paying jobs, and help keep the lights on during extreme weather events.”

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GRIP Programme

The President’s Bipartisan Infrastructure Law provides $10.5 billion across three programmes that make up the GRIP programme to enhance grid flexibility and improve the resilience of the power system.

The programme will deliver projects centred on:

• Grid Resilience Utility and Industry Grants ($2.5 billion) fund for comprehensive transmission and distribution technology solutions that will mitigate multiple hazards across a region or within a community. This is inclusive of wildfires, floods, hurricanes, extreme heat, extreme cold, storms and any other event that can cause a disruption to the power system. Eligible applicants include electric grid operators, storage operators, generators, transmission owners or operators, distribution providers, and fuel suppliers.
• Smart Grid Grants ($3 billion) to increase the flexibility, efficiency, reliability, and resilience of the electric power system. Particular focus will be on increasing capacity of the transmission system, preventing faults that may lead to wildfires or other system disturbances, integrating renewable energy at the transmission and distribution levels and facilitating integration of increasing numbers of electric vehicles, buildings using electricity to heat and hot water, and other grid-edge devices. The programme is open to domestic entities including institutions of higher education, for-profit entities, non-profit entities, state and local government entities, and tribal nations.
• Grid Innovation Program ($5 billion) provides financial assistance to one or multiple states, Tribes, local governments and public utility commissions to collaborate with electric grid owners and operators to deploy projects that use innovative approaches to transmission, storage and distribution infrastructure to enhance grid resilience and reliability.

The first round of funding announced today for GRIP is $3.8 billion for fiscal years 2022 and 2023.

Concept papers are a required first step in the application process. Concept papers for the Grid Resilience Utility and Industry Grants and Smart Grid Grants are due December 16, 2022. Concept papers for the Grid Innovation Program are due January 13, 2023.

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Transmission Facilitation Program

The Transmission Facilitation Program establishes a revolving fund to help overcome the financial hurdles facing large-scale new transmission lines, upgrades of existing transmission lines and, in select states and territories, the establishment of microgrids.

The President’s Bipartisan Infrastructure Law authorises DOE, through the programme, to borrow up to $2.5 billion to assist in the construction of high-capacity transmission lines with an approach that can spur new lines that otherwise would not get built or increase the capacity of already planned lines.

DOE will use capacity contracts to commit to purchasing up to 50% of the maximum capacity of the transmission line. By initially offering capacity contracts to late-stage projects, DOE will aim to increase the confidence of additional investors and customers and reduce the risk of project developers under-building or under-sizing needed transmission capacity projects.

The submission deadline for the first phase is February 1, 2023.

Duke Energy will build new smart grid software and services on AWS and expand its Intelligent Grid Services – a suite of custom-built applications that help the utility anticipate future energy demand and identify where and how to update the power grid.

AWS will work alongside Duke Energy to build out cloud technologies to support Duke Energy’s grid-planning solutions, so they run faster and more cost-effectively.

This collaboration will further Duke Energy’s commitment to use AWS as its primary cloud provider for software development. The utility is also migrating Information Technology (IT) and grid analytics workloads to AWS.

“Our digital evolution is foundational to our clean energy transition,” said Bonnie Titone, senior vice president and chief information officer at Duke Energy.

“For example, to accurately simulate future energy needs and plan investments for the grid, we need to run hundreds of millions of power flow calculations – a process that would take weeks using traditional IT hardware. By using cloud technologies that AWS is developing for Duke Energy, we aim to run those same simulations in 15 minutes or less.”

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These simulations – and other analytics made possible by Duke Energy’s Intelligent Grid Services applications on AWS – deliver insights that will help the utility continue its data-driven grid investment plans.

The applications can forecast where needs will be greatest on the grid and estimate the amount of load the distribution system can accommodate without impacting power quality or reliability.

They are further hoped to recommend the most cost-effective grid solutions needed to meet the evolving needs of customers.

“Duke Energy and AWS share similar commitments to a smarter and cleaner energy future with net-zero carbon emissions,” added Sarah Cooper, general manager of AWS Industry Products.

“These Intelligent Grid Services leverage the proven scalability and reliability of the world’s leading cloud and will help Duke Energy meet energy demands while maximising use of clean energy sources, such as solar and wind power, to serve their customers.”

Duke Energy is executing a clean energy strategy to create a smarter energy future for its customers and communities. This includes investing $145 billion over the next decade in capital projects, the majority of which will go toward modernising the nation’s largest electric grid.

These investments will improve the grid’s reliability and resiliency, connect a growing number of renewables and prepare the grid for rapid electric vehicle adoption.

The 10-year development plan, which has been approved by the Public Service Regulatory Commission (PSRC), includes introducing digital solutions to prepare the transmission network for synchronisation with continental European networks.

In the coming years, AST plans to invest the funds to modernise various aspects of the grid, including commercial electricity, balance control systems, electric network model management systems, the dispatch control system and emergency automation.

These projects – which are hoped to ensure faster and better data exchange and system management – are planned to be implemented before the start of the synchronisation process.

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“In the next decade, we will continue our work on improving the reliability of network operation, systematically renovating the existing and creating new network infrastructure, modernising network management processes and introducing various digital solutions in order to be ready for synchronisation with European power grids in 2025,” said AST board member Arnis Daugulis.

Of the total investment, €210.5 million ($216.6 million) received 75% co-financing from European Union funds.

And until 2033, €21 million ($21.6 million) to €30 million ($30.9 million) is invested annually in the reconstruction of 330kV and 110kV substations, lines and distribution points, ensuring stable operation of the transmission system.

In each project, AST will evaluate infrastructure service life and wear and tear, making sure of the relevance of each project to prevent construction where load would not be ensured in the required volume. According to AST, this is due to their priority for high-quality and safe electricity transmission service at the lowest possible rates.

Additionally, financial investments will be planned to prevent the ageing of transmission equipment in the long term and ensure that no equipment exceeds its critical age.

Grid2030 was a multi-year open collaborative initiative supported by EIT Innoenergy and Red Eléctrica and promoted by Elewit.

The three companies defined different challenges in innovation to find solutions to the problems of the electrical system as more renewables start to come online. These solutions include improving the system’s efficiency and flexibility, promoting the integration of renewables and optimising the performance and accessibility of assets in the transmission grid.

Entrepreneurs and innovators from public and private organisations, universities, research centres and European businesses participated in the development of the three projects.

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The three projects include:

• Flexible Smart Transformer:
  An initiative of Red Eléctrica, Efacec (Portugal), and Circe (Spain). Grids need more flexibility and components with new functionality in the present energy transition. This project presents a modular prototype that uses power electronics and a transformer with magnetic coupling through a dielectric medium rather than a closed ferrite core and high-frequency switching. The combination of each module’s strong isolation capacity will enable the control of voltage levels and grid stability, which will increase the grids’ sustainability and efficiency.
  
• Reduced Inertia Transient Stability Enhancement:
  Developed by experts from the Supergrid Institute (France), the IMDEA Energy Institute (Spain), and Red Eléctrica, the project’s goal was to increase the electrical system’s flexibility in an environment where non-manageable energies are widely used. As tools for system operation, the project specifically created new stability resources and integrated controls to optimise the behaviour of HVDC-VSC links and storage systems.
  
• Enigma:
  A project between Red Eléctrica and Spanish businesses HI Iberia, Ingelectus, and Prysma, the project saw training for Artificial Intelligence (AI) agents to manage the energy that new renewable plants supply to the grid. The agents learned to respond to potential eventualities while keeping the frequency within the required margins using a single-node grid simulator and reinforcement learning techniques. The findings indicate a different approach to controlling these plants from a disruptive standpoint.

A total of €1.6 million ($1.7 million) was invested in the three projects within the framework of the programme, which had been running for four years.

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The Asian Infrastructure Investment Bank (AIIB) and the Global Energy Alliance for People and Planet (GEAPP) announced their partnership during COP27 for the financing of green energy transition and renewable energy projects, in both the public and private sectors.

The partnership will enhance assistance in areas such as co-financing operations and private capital mobilisation.

Capital will be directed to countries eligible to AIIB’s financing activities and that meet the Multilateral Development Bank’s (MDB’s) strategies and policies, while also being areas of GEAPP activity in alignment with and advancement of GEAPP’s objectives.

Simon Harford, CEO of GEAPP stated: “Last year, clean energy generation grew by 522TWh, about a quarter of what is needed to end energy poverty. However, most of this generation occurred in developed countries.

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“As a global MDB, AIIB has the capital, convening power and commitment to invest in innovative, clean energy projects across developing countries, which makes the Bank an ideal partner to join GEAPP. Together we will deliver transformational projects that accelerate and scale the energy transition for communities in Asia and beyond.”

AIIB President Jin Liqun remarked upon the significance of the partnership: “Despite challenges last year, AIIB achieved a 48% climate finance share of total approvals in 2021. Through our timely collaboration, AIIB will continue striving to find new ways to provide our members with access to additional capital and resources.”

Sir Danny Alexander, Vice-President of AIIB, added: “Our participation in GEAPP marks yet another step forwards for our bank, in unlocking new resources through co-financing measures, to meet our ambitious climate targets and deliver value to those most in need.

“As a climate-driven, partnerships bank, our joint work will be focused on project collaboration, and AIIB is delighted to join the alliance of GEAPP as an investment partner in financing a greener, more sustainable future.”

An exchange of Letters of Intent (LoI) was completed at a signing ceremony in Sharm El-Sheik. AIIB’s vice-president of policy and strategy, Sir Danny Alexander, and GEAPP’s CEO, Simon Harford, signed the documentation and were joined by Jin Liqun, president of AIIB; dr. Rajiv Shah, president of The Rockefeller Foundation; Per Heggenes, CEO of IKEA Foundation; and dr. Andrew Steer, president and CEO of Bezos Earth Fund. 

The partnership follows prior cooperation between AIIB and GEAPP over the past year and is the first time AIIB has partnered with a global philanthropic foundations-led initiative.

SF6 is a gas commonly used in the power industry to provide electrical insulation and arc interruption. However, SF6 is a potent greenhouse gas with a global warming potential that is 25,200 times greater than CO2.

The £1.9 million ($2.1 million) project will see experts at Manchester help determine how National Grid can develop a retrofill solution to replace SF6 with an environmentally friendlier alternative without having to replace or otherwise modify existing equipment.

This project will bring together the interdisciplinary expertise of Manchester’s department of electrical and electronic engineering and the department of chemical engineering, led by Dr Tony Chen with professor Philip Martin.

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SF6-free retrofill

Together the university and National Grid will create a physical demonstration, including an inbuilt condition-based monitoring system, that will focus on the applicability of SF6 retrofill techniques. It will be developed in Manchester’s high voltage research laboratory, equipped with facilities that can test up to 600kV DC, 800kV AC, and 2MV impulse, and has been the testbed for developing solutions such as improved designs of high voltage overhead lines and developing safer, greener high voltage transformers using ester liquid.

The project builds on Dr Tony Chen’s expertise in SF6, and it is anticipated its findings will give asset managers the information required for retrofilling significant quantities of SF6-filled equipment across the transmission network, bridging the current gap between established feasibility, and long-term, real-world implementation.

Dr Chen said on the project: “This project will provide the missing link – taking the success of the research in this area so far, and creating a way to apply retrofilling at scale. By bringing together the expertise of two Manchester departments, we can address every element of this challenge, catalysing the development of real-world solution, which protects the environment while providing significant economical saving.”

Mark Waldron, technical lead at National Grid Electricity Transmission, added: “It’s exciting to be following the world-first SF6 retrofill in Richborough substation with this initiative taking us a step closer to a solution to replace the gas in more of our assets. The potent combination of Manchester’s expertise in this area and the innovation and demonstration capability at our state-of-the-art Deeside facility will deepen our understanding of retrofill solutions and could boost our progress in the decarbonisation of the grid while achieving a significant cost benefit for consumers.”

National Grid’s Deeside centre for innovation in North Wales is stated by the company as the first of its kind in Europe, where electricity network assets can continuously be tested under real life conditions.

The facility provides a controlled test and demonstration environment to collect data, including a high voltage substation and overhead line test area simulating real network conditions.

The nearly €1 billion investment also aims to deploy renewable energies, facilitate Catalonia’s energy transition and continue improving the quality of the service received by the company’s 4.4 million customers in the region.

Through its distribution subsidiary, e-distribución, Endesa plans to carry out nearly 1,300 projects throughout Catalonia, aimed at improving the digitalisation, reliability, resilience, flexibility and efficiency of Endesa’s extensive distribution grid in Catalonia, which represents 39% of the company’s capacity in the region.

The actions will focus mainly on any axes that make it possible to continue digitising Catalonia’s grid, guaranteeing its robustness and resilience, facilitating access to renewables, improving the quality and continuity of supply and preparing the infrastructures for the increase in demand as a result of electrification (expected to increase by about 7,500MWh within three years).

The plan

The investment was planned after prioritising the region’s most immediate requirements, while being aware of the crucial role played by the distribution grid on individual quality of life, since it allows electricity to reach homes, industries and services, connecting transport networks and generation plants with consumption points.

Specifically, Endesa plans to act directly on more than 11,100km of high, medium and low voltage lines, with a particular focus on the investment effort in low voltage, which stands at almost 189.3 million euros. The company foresees improvements in more than 4,700km of low-voltage cables between 2023 and 2025.

Executing these actions is expected to generate more than 2,900 jobs, direct and indirect, at a rate of about 960 jobs per year.

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Digitalisation of the grid

In the period 2023-2025, Endesa plans to install nearly 15,000 remote controls throughout Catalonia, to exceed 33,000 within three years and continue the deployment launched in recent years.

In addition, new line switches will be installed and act automatically in the event of incidents in the grid, in order to isolate the damaged sections and restore the supply in the shortest possible time.

Another key element in this transformation is the sensorisation of the transformation centres, which consists of monitoring the status of transformers and low-voltage grids, so as to observe and analyse the performance of parameters such as voltages and temperatures in order to control their correct operation and achieve preventive and predictive digital management of these assets.

According to Endesa, first deployed in 2018, this initiative has been in gradual crescendo. During the next triennium, Endesa plans to install around 27,800 across Catalonia, to reach approximately 50,200 by 2025.

Digitalisation, therefore, extends throughout the entire infrastructure of the distribution grid, from its systems and processes to the customer service channels. By using it, the focus is on improving the quality of supply to customers, so that supply disruptions and incident response times are reduced, whether they are their own or derived from external agents.

It also leverages the potential of big data and artificial intelligence to improve operations in an increasingly data-driven decision-making process.

 The projects underway include the Network Digital Twin, an exact replica of the assets with which simulations can be carried out in all possible conditions. This digital twin opens the door to data-driven network management, real-time control of the operation of different components, preventive maintenance and more efficient interaction with field personnel.

Regarding Catalonia’s grid and electricity operations, Endesa has 45,669 transformation centres, 208 substations, 126 distribution centres and 98,910km of power lines (low, medium and high voltage) distributed in the region.

The investments, worked together and approved by the Generalitat of Catalonia, are in addition to the €263.7 million ($260.9 million) that Endesa is already allocating this year to the distribution grid within the framework of the current triennium (2021-23).

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VEIR is coordinating this first application of superconducting transmission over long distances, which is needed to safely and reliably deliver renewable sources of energy from where it is generated to where it is needed, often across the country.

Electricity, natural gas and clean energy delivery company National Grid will aid VEIR in product development with the joint aim of demonstrating the new technology on a protected area of the grid. 

“With climate change, it’s increasingly critical to decarbonise the energy system by connecting more renewable resources while using existing rights of way and other infrastructure,” said David Wright, National Grid’s group chief engineer.

“National Grid is eager to help develop and deploy new technologies that can improve the capacity of existing lines, so we can increase the flow of clean energy without impacting the customers and communities we serve.” 

Under the collaboration agreement between the two, National Grid engineers will help proof VEIR’s work by providing constructive feedback during all phases of development, with an emphasis on how best to integrate this new technology into the larger electric grid.

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Superconductors can transmit 5 to 10 times the capacity of conventional transmission lines, but earlier applications of the technology use underground closed loop systems with mechanical refrigeration stations that have multiple moving parts.

This has hampered their broad scale grid deployment. VEIR uses an open system where evaporative cooling distributed along the entire distance of the transmission lines is used to keep the superconducting material cold. The simpler, lighter components allow for overhead deployment over long distance. 

“VEIR shares National Grid’s commitment to a fossil-free world, and this collaboration agreement adds momentum to VEIR’s development of technology that we believe will eventually deliver clean energy into the grid safely, reliably and faster than the existing system,” stated Adam Wallen, VEIR’s chief executive officer.

“We are thrilled to be working with one of the industry’s preeminent, forward-thinking companies. The practical experience that National Grid’s engineers have gained from running transmission systems around the world will help us accelerate the safe and reliable deployment of our high-capacity transmission lines.”

“National Grid’s collaboration with VEIR is a perfect intersection of our mission to discover and deploy startup technology that can help National Grid continue its leadership in the renewable energy future,” stated Lisa Lambert, chief technology & innovation officer of National Grid and founder & president of National Grid Partners.

“VEIR is working on a transformative technology for the electric grid, and this collaboration will combine the strengths of an innovative startup with the scale and expertise of an established industry leader.”

The contracts were signed yesterday between the country’s Ministry of Energy and the national electric power transport company, Transelectrica SA.

Romania’s investment

Prime minister of Romania Nicolae-Ionel Ciucă stated on the announcement: “Today we signed the first financing contracts from the Modernisation Fund, opening the most important line of European funds intended for the development of the Romanian energy sector.

“Solutions to protect citizens and the economy from the effects of rising prices are complemented by investments in strengthening energy infrastructure and increasing production capacities. The government, through the Ministry of Energy and the responsible institutions, remains engaged in the efforts to ensure accessible energy for Romanians and the national economy.”

The investments aim to both modernise electricity transmission capacities and improve energy efficiency, security and flexibility in the country, through the construction of new overhead power lines and their interconnection to the SEN (National Energy System).

It is hoped that this will help develop premises for the commissioning of new renewable energy production capacities.

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9 grid modernisation projects

The nine projects that have obtained funding from the Modernisation Fund include:

1. Digitisation of the electricity transmission network in Romania by installing two online systems, for the metering and management of electricity measurement data on the wholesale market and for monitoring the quality of electricity – with a value of over €18 million ($17.5 million).
2. A pilot project refurbishment of the 220/110/20kV Alba Iulia station – a digital station concept – with a value of approximately €47 million ($49.6 million)
3. Construction of a 400kV LEA (double circuit) Constanța Nord – Medgidia Sud, equipped with a single circuit – with a value of approximately €23 million ($22.3 million)
4. Construction of a new 400kV Gădălin – Suceava single-circuit LEA, including its interconnection to the national electricity transmission system – with a value of over €101 million ($98 million)
5. Internal line between Reșița and Timișoara/Săcălaz (PCI 3.22.3.), consisting of a new 400kV LEA Reșița-Timișoara/Săcălaz and in the 400kV refurbishment of the 110/2020 kV Timișoara substation – with a value of approximately €64 million ($62.1 million)
6. Construction of the 400kV LEA Timișoara/Săcălaz/Arad – with a value of over €57 million ($55.3 million)
7. Switching to the 400kV voltage of LEA Brazi Vest-Teleajen-Stâlpu – with a value of about €51 million ($49.5 million)
8. Installation of two modern reactive power compensation means in the 400/220/110/20kV Sibiu South substations of 400/220/110/20kV Bradu – with a value of over €52 million ($50.5 million)
9. Optimisation of the operation of the existing 400kV LEA in the SEN, used in interconnection and for the evacuation of power from the Cernavodă nuclear power plant and the power plants from renewable sources in Dobrogea This will be done by installing online, smart grid-esque, systems with a value over €10 million ($9.7 million).

Ultimate benefits

According to the country’s energy ministry, the major benefits of these investments will include:

• Increased transmission capacity by approximately 1700MW
• Approximately 480km of new overhead power lines
• Expansion of five electrical stations with a voltage level of 400kV
• Digital re-engineering – a first for Romania – of the Alba Iulia Station
• Increasing interconnection capacity by 600MW (cumulative on the borders with Serbia and Hungary)
• Electricity quality monitoring systems in 15 stations

The Modernisation Fund is a financing instrument made up of the revenues obtained by auctioning on the market 2% of the total greenhouse gas emissions certificates, based on the provisions of the EU-ETS Directive and has, as an implementation period, the 2021 timeframe -2030.

Around the world, governments, enterprises and utilities have set ambitious goals to reduce carbon emissions on their journey toward net zero in 2050. This transition from fossil fuels, which in Europe has accelerated with Russia’s invasion of Ukraine, is driving the electrification of transportation, home heating and cooking, agricultural production and many industrial processes from concrete to steel worldwide.

After years of nearly flat demand, the energy transition is generating a growing demand for electricity with the most inexpensive non-carbon alternatives being renewables such as solar and wind, which are reaching price parity with coal and gas in many areas of the world.

Even as utilities face new spikes in demand as transportation, households, farms and industries electrify, they are also seeing shifts in generation, especially with distributed energy resources such as rooftop solar and home storage. These new distributed generation sources create bi-directional energy flows that pose a challenge for utility grids, which need to become more flexible and dynamic to balance rapid shifts in both generation and consumption.

This will require greater intelligence and communication between nodes on the grid. Artificial intelligence and machine learning (AI/ML) will play a critical role in balancing the grid with advanced software systems that enable utilities to automate and streamline operational control. Linking these distributed energy resource management systems (DERMS) to all the nodes on the grid will also require an upgrade to the utility’s communication network.

IP/MPLS: Meeting the needs of the modern grid

With so many changes happening in the energy industry, it may come as a surprise that many utilities are turning to a communication technology that has stood the test of time for nearly a quarter of a decade. Companies, such as Ameren in the United States, Finland’s Fingrid, Spain’s Red Electrica, France’s Réseau de Transport d’Électricité (RTE) and Greece’s Independent Power Transmission Operator (IPTO), are just a few of the many energy companies choosing IP/MPLS networks for their grid modernisation.

One reason is IP/MPLS’ ability to support a mix of applications on the same network, both new and old, including those that previously required support on dedicated networks using legacy TDM/SONET/SDH technologies. IP/MPLS is more than capable of meeting the strict low latency demands needed for grid protection (including current differential protection), while also supporting applications such as SCADA, voice, CCTV security monitoring and many new IP-based applications.

The ability of IP/MPLS networks to provide the required performance for applications such as synchrophasor monitoring – devices that take precise measurements 120 times more frequently than was possible using SCADA – is what enables DERMS to precisely balance the grid as demand and generation rapidly shift. With its multicast abilities, IP/MPLS also supports the multiple flows of data that DERMS uses to manage the grid. IP/MPLS can also support critical voice communications and augmented reality applications for greater visibility and efficiency in operations and maintenance.

US power company Ameren, which serves 2.4 million electric and 900,000 gas customers, has seen how IP/MPLS can transform grid protection and control. The company replaced legacy leased lines over copper by rolling out a private IP/MPLS fiber network in 2017 to improve reliability for its customers. The Ameren network was used to connect hundreds of substations, operations centres and other critical locations spread across both densely populated areas, industrial cities and stretches of farmland in the states of Illinois and Missouri.

Ameren redeployed teleprotection support to the new IP/MPLS network, which provided the quality of service (QoS) required for this latency-sensitive application. By improving protection systems, substations can react more quickly to isolate faults, thereby adding resilience to the services Ameren can provide its customers. 

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Growing adoption of IP/MPLS

As utilities move away from centralised power sources and control, they need to adapt to changes in the way that power is generated and consumed. IP/MPLS allows flexibility in design and deployment and the highest resilience. This flexible approach to design includes simplifying the way connections are provisioned, with nodes automatically recognised on the network.

IP/MPLS also gives utilities the option to choose between fiber, microwave radio, private LTE or telco Ethernet services transport, so they can choose the best medium available, making it an even more attractive and easy-to-integrate solution.

As one of Europe’s leading users of renewable energy, Finnish national transmission system operator (TSO), Fingrid, was charged with finding a more agile and automated way to manage and balance new variable, bi-directional power flows. When Fingrid wanted to digitalise and automate the management of its national electricity grid to manage the growing adoption of variable DERs, such as wind, solar and bioenergy, it turned to IP/MPLS as the resilient, reliable technology.

Spanish TSO, Red Eléctrica, announced last year that it too will modernise its communications network using IP/MPLS and Dense Wave-Division Multiplexing (DWDM) optical transport to replace a legacy synchronous digital hierarchy (SDH) fiber network. This will support grid operations across 800 sites nationwide, including the Canary and Balearic Islands.

The networks will provide the Spanish utility with enhanced bandwidth and efficiencies to manage DERs such as rooftop solar and residential power storage. It will provide support for substation communications as well as low-latency transfer of IoT sensor data required for measurement, protection and control activities for SCADA systems and synchrophasors.

The French TSO, RTE, is responsible for the nation’s high-voltage transmission system, which includes more than 105,000km of lines and 50 interconnection points with neighboring countries. Balancing supply and demand on a per-second basis required RTE to invest heavily in digital technologies to make its grid smarter and capable of handling future electricity usage patterns. That investment included replacing its older PDH/SDH-based network with IP/MPLS.

This not only upgraded the network but made it possible for RTE to adopt modern IP-based smart grid applications to extend remote monitoring, control, and automation to nodes throughout its network. At the same time, it supports legacy applications such as teleprotection and differential protection. The new network supports a wide variety of use cases including IP VPN services to connect applications, assets and personnel.

Looking to the future, IP-capable networks are essential for supporting IEC 61850 standards, which will advance the digitalisation of substations and enable the deployment of smarter grid protection schemes, such as wide-area protection. And because Ethernet and IP interfaces provide latency an order of magnitude lower than that supported by TDM interfaces, TSOs like RTE can even consider using cloud computing to virtualize grid protection and control functions in the future.

Constantly evolving to tackle cybersecurity threats

Security is a major concern for any utility. As power sources become more distributed throughout the grid, ensuring security becomes more challenging. Power utilities are an essential service, keeping homes warm and lit, and our economies on track. They power industries, hospitals and other vital infrastructure. With growing cyberterrorism threats, the power industry is one of the most rigorously regulated industries in many countries.

Networks are highly scrutinised and must comply with the strictest standards and regulations around the globe such as those set by the North American Electric Reliability Corporation Critical Infrastructure Protection (NERC CIP) as well as ENISA – the European Agency for Cybersecurity. 

Since its introduction, IP/MPLS has evolved, being made more robust to tackle the growing number of cybersecurity threats. Today IP/MPLS networks boast extensive defense-in-depth (or zero trust) security features that allow utilities to combat cybersecurity threats and ensure the continuous flow of data to deliver safe, reliable power to their customers. 

Cutting complexities in an ever-changing world

It’s clear to see why more and more utilities are choosing IP/MPLS for their network transformation. In addition to its evolution over the last 20-plus years, and to remain secure as threats of cyberattacks increase, it also has the flexibility to adapt and accommodate the needs of newer, greener, distributed energy sources as they are incorporated within the power grid. It’s this reliability and scalability of IP/MPLS that will help utilities as they transition toward a net zero emissions future.

ABOUT THE AUTHOR

Dominique Verhulst leads Nokia’s Global Energy Practice, with over 30 years of experience in the telecommunications industry. He and his team provide complete end-to-end solutions to utilities, oil&gas and mining companies.

He is the author of “Teleprotection over Packet Networks”, and co-author of several publications from the University of Strathclyde.