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

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

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

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

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

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

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

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

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

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

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

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

Expanding transmission grids capacity

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

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

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

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

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

Preparing the grid

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Against this, general principles suggested for the future are:

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

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

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

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

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

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

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

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

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

Business use cases

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

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

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

Data space connector

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

“We need to do something before it is too late,” said Julia Poliscanova, senior director for electric vehicles at European NGO, Transport & Environment.

Currently, China leads the worldwide EV market and Europe is second. A report released this week by EY and electricity association Eurelectric highlights that the European electric vehicle market is booming and predicts there will be more than 75 million EVs on Europe’s roads by 2030.

And yet the US is in Europe’s rear-view mirror and catching up fast, fuelled mainly by the implementation of the Inflation Reduction Act, the Biden administration’s investment-stimulating legislation introduced in 2022.

“Technically, the US is behind,” said Poliscanova. “But with the IRA, they are catching up super-quickly.”

Her warning was echoed by Marc Coltelli, EY’s Americas e-mobility energy leader, who said the White House had “taken strong steps to stimulate the e-mobility eco-system”.

“The US is behind… but it’s not going to be behind for long. The chance to grow over the next decade is huge.”

He predicted that the US would match Europe’s current levels of EV adoption in just three years because there was already free-flowing collaboration between utilities, carmakers, chargepoint providers and other actors in the EV supply chain. “The excitement around EVs is huge.”

Poliscanova and Coltelli were taking part in a panel discussion this week at EVision, a Brussels-based e-mobility symposium organised by Eurelectric.

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Joining them on stage was Mark Nicklas, Head of Unit at DG GROW in the European Commission, who stressed that being number two globally was a success story.

And he was confident Europe could hold that position: “We have all the enabling framework in place: the next step is implementation.”

He said the US “has a simple framework, while Europe is much more complicated”. However, he said that when EU policies were added up, they were “not so much different from the IRA”.

Poliscanova disagreed. She said Europe’s policies were too mixed and lacked the pulling power to attract investment.

She called for a green industrial policy, a European investment strategy and a made-in-EU approach to “bridge the gap between producing [EVs] in Europe and producing somewhere else”.

She said Europe had a “lot of strong ingredients, but we need a stronger cook”.

And she urged policymakers and industry to “be more bullish. We should just ‘do’ and not question whether to ‘do’. The future of decarbonisation is the intersection between energy and transport, and we need much smarter legislation.”

She was full of admiration for Europe’s EV journey so far – “Every fifth vehicle sold in Europe is electric” – yet she warned, “we are with EVs and batteries where we were with solar”.

A avoid a similar scenario, she said: “We need a different vision for trade – a holistic vision.”

With this adoption, the Bureau is foreseeing the enablement of interoperable, multi-service and secure wireless communications networks for government, utilities, service providers and enterprises in India.

Under the Revamped Distribution Sector Scheme, which was introduced in July 2021, a nationwide rollout of more than 250 million smart meters is currently underway, while also large-scale smart city development is underway with the government having allocated support towards the development of 100 smart cities in the country.

“The adoption of the Wi-SUN Alliance wireless communications specification as a standard for India by the BIS is a clear signal that the national standards body recognises the role that wireless mesh technology will play in driving the growth of smart cities in India and the rapid rollout of smart meter projects over the next few years,” commented Phil Beecher, President and CEO of the Wi-SUN Alliance.

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Reji Pillai, President of the India Smart Grid Forum and Chairman of the Global Smart Energy Federation, said the Forum has been closely associated with the Wi-SUN Alliance for over a decade and described India’s adoption of the Wi-SUN FAN as a great achievement.

“In India we should ideally make it mandatory for all smart metering and smart city applications which will ensure interoperability between different systems and reduce total cost of ownership of all applications.”

Wi-SUN’s wireless mesh technology is currently supporting the Smart City Living Lab project in Hyderabad, a partnership between the International Institute of Information Technology (IIIT-H), the government of Telangana and Ministry of Electronics and Information Technology India that serves as a test bed for smart city technologies.

The Wi-SUN Alliance is already running the Wi-SUN FAN PHY certification programme for the Indian frequency band (865-868MHz), with testing at TUV Rheinland Bangalore.

The Alliance is also working to start the certification programme for the Wi-SUN FAN specification. The test setup available for Wi-SUN FAN certification can also be used for IEEE 2857 and BIS standard IS 18010 (Part4/Sec1) compliance testing and verification.

The Wi-SUN FAN specification is aimed to support the specification and rollout of large-scale outdoor networks including smart metering projects, smart grids, street lighting and other IoT applications.

Wi-SUN Alliance member companies based in India include Cisco, Renesas, Silicon Labs, Texas Instruments, Exegin and CyanConnode.

The electricity network development plan 2023-2037/2045 includes the need for 4,800km of new lines and the reinforcement of 2,500km of existing connections, compared to the existing federal requirements plan.

“This network development plan shows for the first time which electricity network we need to complete the energy transition. We have carefully examined all proposed projects. For a climate-neutral electricity system, we need a significant amount of additional power lines by 2045,” explained Klaus Müller, president of the Federal Network Agency, in a release.

“We have only defined the start and end points of the lines in the network development plan. The exact route of the lines have not yet been determined, but will be determined in subsequent process steps.”

HVDC and offshore connections

With the development plan, the Federal Network Agency also confirmed five new high-voltage direct current (HVDC) transmission connections with a capacity of 2GW each :

• DC32 from Schleswig-Holstein to Mecklenburg-Western Pomerania
• DC35 from Lower Saxony to Hesse
• DC40 from Lower Saxony to Saxony
• DC41 from Lower Saxony to Baden-Württemberg
• DC42 from Schleswig-Holstein to Baden-Württemberg

The plan also includes measures to connect offshore power generation to the onshore transmission network.

The Federal Network Agency considered 35 additional projects in the North and Baltic Seas to be necessary by 2045.

The lines connect up to 70GW of power from offshore wind farms to the mainland, a goal set out in the Windsee Law.

The network development plan contains the network connection points on the mainland where wind energy generated at sea can best be integrated into the transmission network.

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In response to the announcement from the Federal Network Agency, Kerstin Andreae, chairwoman of the Executive Board of BDEW, the German business organisation for the energy and water industry, said in a release:

“The confirmation of the network development plan is pleasing. It is now important to implement this quickly and move forward with the creation of the appropriate legal and regulatory framework. The approved network development plan makes clear the urgency of rapid network expansion.”

However, although Andreae lauds the plan’s confirmation, she added the need for a reliable and competitive investment framework, “especially at this time, when network operators are more dependent than ever on international investors … In addition to the investments in the transmission networks, there are additional investments worth billions in the conversion and expansion of the distribution networks to be able to reflect the new needs of network users.

“Network operators are rising to this challenge. But you also have to be able to rely on the Federal Network Agency offering a reliable and competitive framework for investments.”

In the network development plan, the four German TSOs – Amprion, TransnetBW, TenneT and 50Hertz – determine every two years which measures are necessary to optimise, strengthen and expand the high-voltage electricity network.

Germany’s Federal Network Agency examines and confirms these proposals with a federal requirements plan subsequently approved by legislature listing the required management projects.

CER refers to smaller-scale energy resources owned by customers, which can produce, store, or vary how they use energy. Newer forms of CER include clean tech assets such as solar panels, batteries and EVs, as well as more traditional assets such as hot water heaters and pool pumps.

As part of a broad set of reforms, the AEMC announced a priority for customers to make better use of these CERs and contribute to grid stability.

In a release, AEMC chair Anna Collyer said investing in these resources empowers consumers to generate, consume, store and trade energy according to their preferences.

“By using these assets in a smart way, customers can lower their energy bills, and should they choose, share the power they generate or vary their consumption in such a way that it supports the overall grid,” said Collyer.

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A draft determination paper by the AEMC outlines positions on how to unlock the benefits of CER, with new arrangements made for:

• ‘Flexible’ trading by enabling all customers to have CER separately metered and therefore identified and managed separately from other ‘passive’ consumer loads such as lights and fridges.
• Large customers choose multiple energy service providers for their premises.
• An in-built measurement capability in technology such as streetlights and EV chargers to be used instead of additional meters, which allow for the measurement and management of energy use at lower cost.

The AEMC states the reforms as part of their work to create greater visibility of price-responsive resources, such as household batteries, making it easier for customers to participate in the power market, while helping AEMO and networks to operate the system more efficiently.

Added Collyer: “The key to a successful transition is integrating these resources effectively into the National Electricity Market. Our only choice is to be well prepared.

“If we do not properly integrate CER into market processes, we face materially higher generation, network and intervention costs. Consumers have a critical role in the transition – but to do so – they need sound policy decisions from us all.”

Further network reforms discussed in Canberra

Days following the announcement from the AEMC, The Energy and Climate Change Ministerial Council (ECMC) met in Canberra, Australia, and committed to undertaking reforms on network planning through a National Consumer Energy Resources Roadmap.

The roadmap will deliver reforms on new consumer protections, network reforms to allow consumers to export more solar power to the grid, as well as nationally consistent standards in key areas, including vehicle to grid (V2G) technologies.

By doing so, states the Council in a communique, downward pressure will be placed on overall system costs and consumer bills, while contributing to emissions reductions and broadening access to CER.

According to the communique, reforms in each of these areas are already underway, such as those being coordinated by the AEMC, including streamlining connection processes, making Service and Installation Rules nationally consistent, and establishing standards and a regulatory framework for CER.

In response to the statements, Energy Consumers Australia CEO Brendan French commented in a release:

“Energy Consumers Australia welcomes today’s announcement that governments will develop a consumer-focused reform package to present at the next energy ministers meeting in July.

“There are just too many barriers that prevent people getting better energy deals, particularly people in financial stress or experiencing disadvantage. Pricing structures are too complex and it is difficult for consumers to understand the terms they see on their bills.

“Our research has found that 32% of homeowners and 44% of renters say they are unsure which tariff structure they are on. Many people simply cannot participate in a market as arcane as this one.

“We also support the government’s commitment to undertaking reforms through a National Consumer Energy Resources Roadmap. There are many instances now where people and communities are not only consumers, but suppliers of energy and they should be fairly rewarded for the generation, storage and services they provide to the system.”

To support the decision-making process, Microsoft has launched a guide on the North American Electric Reliability Corporation’s Critical Infrastructure Protection (NERC CIP) standards, which play a crucial role in ensuring the security and reliability of the electric grid.

Updates to NERC CIP guidelines

As of January 1, 2024, significant changes have been implemented, allowing the storage of medium- and high-impact Bulk Cyber System Information (BCSI) in the cloud, subject to specific requirements.

By embracing cloud technologies, while adhering to NERC CIP guidelines, power and utilities leaders can enhance operational efficiency, promote sustainability, and ensure grid reliability.

As the energy sector evolves, proactive engagement with NERC CIP standards will be pivotal in shaping a resilient and interconnected future.

1. Cloud Adoption and Security
   • The recent changes permit power companies to leverage cloud infrastructure for storing BCSI. While this opens up new possibilities for scalability and efficiency, it also introduces security challenges.
   • Organizations must carefully evaluate cloud service providers, ensuring compliance with NERC CIP requirements. Robust encryption, access controls, and continuous monitoring are essential.
     
2. Benefits of Cloud Adoption
   • Cloud-based storage offers flexibility, enabling seamless data sharing across geographically dispersed teams. It promotes collaboration and accelerates decision-making.
   • Scalability allows utilities to handle increasing data volumes, especially with the proliferation of smart meters and IoT devices.
   • Cost savings result from reduced on-premises infrastructure maintenance and operational expenses.
     
3. Challenges and Mitigation Strategies
   • Security Concerns: Cloud adoption introduces potential vulnerabilities. Companies must implement robust authentication mechanisms, intrusion detection systems, and regular vulnerability assessments.
   • Compliance: Organizations must align cloud practices with NERC CIP requirements. Detailed documentation, audit trails, and incident response plans are critical.
   • Data Residency and Sovereignty: Address legal and regulatory aspects of data storage locations.
   • Third-Party Risk: Evaluate cloud providers’ security practices and contractual agreements.
     
4. Future Outlook
   • The evolving landscape of cybersecurity necessitates continuous adaptation. Companies should actively participate in shaping future NERC CIP standards.
   • Collaboration among industry stakeholders, regulators, and technology experts will drive innovation and resilience.

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The European Commission is making available €74 million (US$80 million) in funding towards the creation of the energy and other sectoral data spaces as part of an over €176 million ($191 million) package for the Digital Europe 2023-2024 work programme.

The sectoral data spaces, a key component of the EU’s data strategy, are intended to form repositories for pooling, accessing, sharing and processing data from within the respective sectors from across the EU.

Based on common data infrastructures and governance frameworks, their evolution is being driven by users within their respective sectors.

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Over time the goal is for them to be gradually interconnected, furthering the data sharing – for example, energy with mobility opening the energy sector to wider participation – and ultimately forming a single market for data that can assure Europe’s global competitiveness and data sovereignty.

Energy data space

With various initiatives well under way towards the energy data space, proposals for the 2023-2024 programme should foresee the deployment of the first version, building on these, in at least ten member states with piloting of at least five use cases in areas such as distributed energy resources management, provision of flexibility services for electricity grids or smart and bi-directional electric vehicle (EV) charging.

These should use a commonly agreed reference architecture with replicable and scalable building blocks, e.g. on data models and formats, data exchange APIs, data provenance and traceability, metadata, etc.

In particular regarding data interoperability arrangements, the data space should be based on agreed minimal interoperability mechanisms that will align energy-relevant key stakeholders on a set of minimal sufficient capabilities needed to achieve interoperability of data, systems and services between the key players of the energy value chains at all levels, i.e. European, national and local.

Another requirement is the consideration of a complete set of open standards, while other deliverables required are the definition of suitable business models that can ensure financial sustainability of the energy data space beyond the end of the project and the implementation of a governance system for overseeing its operations.

An amount of €8 million ($8.7 million) is allocated for this energy data space advancement, which is expected to take place over 36 months.

In addition to the support for the data spaces, the €176 million package includes funding to advance research and use of artificial intelligence, for projects on the cloud to edge infrastructure and for skills development.

The rollout follows the regulatory approval given in September 2023, which authorised up to $153 million for the initiative and forms part of Rhode Island Energy’s grid modernisation activities to enable the integration of renewable energies to support the state’s climate goals.

The Revelo metering platform features grid edge sensing and edge computing capabilities to manage load and support grid troubleshooting, with the Revelo meter operating on Landis+Gyr’s RF Wi-SUN network.

Additionally, the advanced grid-edge processing allows for greater consumer engagement with applications such as real-time load disaggregation and pricing information.

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“The Commission’s approval to implement our advanced metering plan is an important step in modernising the state’s energy infrastructure for the benefit of all Rhode Islanders,” said Dave Bonenberger, president of Rhode Island Energy, of the approval.

With the prospect of being able to benefit from parent company PPL Corporation’s other smart meter rollouts in Pennsylvania and Kentucky, he continued: “We’ve seen the success of these new technologies across other PPL service territories, and customers should be excited about the advantages they’ll bring to their homes and businesses.”

The rollout is timely as approximately 60% of the electricity meters across the state are nearing the end of their design life and need to be replaced.

Before the start of the rollout, which is expected to begin in 2025 and to be completed over the following three years, Rhode Island Energy intends to engage customers to provide more details about the technology in advance of installation, as well as an opt-out option.

In October 2023 Rhode Island Energy was selected to potentially receive up to $50 million in federal funding from the Infrastructure Investment Act towards its almost $300 million smart grid investment programme to improve visibility and control on its grid.

Among the plans are advanced distribution management and energy management systems and a centralised asset hub data system and geographic information system to represent a digital twin of the grid.

Providing a comprehensive understanding of grid orchestration, its challenges, and the transformative potential it holds, this eBook focuses on:

1. Grid Orchestration: The art of harmonising diverse energy sources, demand patterns, and grid infrastructure.
   • Explore the role of artificial intelligence, machine learning, and predictive analytics in optimising grid operations.
     
2. Decentralisation: The shift toward decentralised energy production.
   • Decentralised grids empower local communities, enhance resilience, and reduce reliance on centralised power plants.
     
3. Smart Grids: Smart grid technologies, including advanced sensors, real-time data analytics, and demand-side management.
   • Smart grids enable efficient load balancing, fault detection, and self-healing capabilities.
     
4. Cybersecurity Challenges: Grid orchestration faces cybersecurity threats due to increased connectivity.
   • The importance of robust security measures to safeguard critical infrastructure.
     
5. Renewable Integration: Integrating renewable energy sources seamlessly into the grid.
   • Addressing challenges related to intermittency, storage, and grid stability.
     
6. Policy and Regulation: Policy frameworks and regulatory aspects influencing grid orchestration.
   • Balancing innovation with compliance is crucial for a sustainable energy future.

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“Orchestrating the Grid” eBook, serves as a roadmap for energy professionals, policymakers, and researchers. By embracing grid orchestration, together we can create a resilient, efficient, and sustainable energy future.

North America’s National Association of Regulatory Utility Commissioners (NARUC) partnered with the US Department of Energy’s Office of Cybersecurity, Energy Security and Emergency Response (CESER) to develop a set of cybersecurity baselines.

Coupled with forthcoming implementation guidance, the baselines are intended as resources for state public utility commissions, utilities and DER operators and aggregators, encouraging alignment across US states on energy cybersecurity.

Regulatory oversight of electric distribution systems and DERs occurs at the state level in the US. The guidance developed by NARUC through CESER’s funding, will help provide states with uniform cybersecurity baselines instead of a patchwork of cybersecurity requirements across the country.

Further, the baselines will enable electric companies and DER providers to work with state utility commissions and energy offices, boards and communities to prioritise cybersecurity investments across the US.

The guidelines, to be developed in 2024, will include recommendations for assessing cybersecurity risks and prioritising assets the baselines might apply to.

“Safeguarding America’s energy infrastructure and advancing US cybersecurity capabilities is critical to achieving President Biden’s ambitious climate goals,” said US Deputy Secretary of Energy David M. Turk in a DOE-issued release.

“Today’s announcement underscores the Biden-Harris Administration’s commitment to working with key partners, like NARUC, to develop vital cybersecurity solutions and strengthen the resilience of America’s electric systems.”

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The growing cyber threat

The baselines represent the growing urgency of cybersecurity across sectors in the US.

In the DOE’s statement on the baselines, they state that cyber threats have been increasingly sophisticated and target critical energy infrastructure more frequently than ever before.

Earlier in February, the US Cybersecurity and Infrastructure Security Agency (CISA), National Security Agency (NSA) and Federal Bureau of Investigation (FBI) released a cybersecurity advisory on the threat posed specifically by cyber actors sponsored by the People’s Republic of China.

The advisory assessed that these Chinese state-sponsored cyber actors are seeking to pre-position themselves on IT networks for disruptive or destructive cyberattacks against US critical infrastructure, including energy, in the event of a major crisis or conflict with the country.

The assessment was based on observations from incidents at critical infrastructure organisations compromised by the cyber group known as Volt Typhoon, warning infrastructure organisations, such as the DOE, of the threat.

According to the advisory, agencies observed indications of Volt Typhoon actors maintaining access and footholds within some victim IT environments for at least five years, conducting pre-exploitation reconnaissance to learn about the target organisation.

According to NARUC, the initiative recognises that cybersecurity is an integral underpinning of power system resilience and builds on work that states have undertaken over the last decade to mitigate risk across their critical infrastructures.

The cyber baselines are based on DOE’s work on energy sector cybersecurity and the US Department of Homeland Security’s Cybersecurity Performance Goals (CPG).

NARUC convened a steering group of industry and government subject matter experts, including electricity sector owners and operators, state regulatory agencies, cybersecurity experts and others to inform the baselines.

Currently, each of Ontario’s 58 local electricity utilities have different procedures for connecting new public EV charging stations, with different timelines, information requirements,and responsibilities for customers, the Ontario government said.

As of December 2023, there are more than 150,000 EVs registered in Ontario, including both battery-electric vehicles (BEV) and plug-in hybrid electric vehicles (PHEV). By 2030, there are expected to be more than one million EVs on the road in Ontario.

In response to Minister Smith’s Letter of Direction, which called on the Ontario Energy Board (OEB) to take steps to facilitate the efficient integration of EVs into the provincial electricity system, the OEB issued provincewide, streamlined procedures that all local utilities must follow for installing and connecting new EV charging infrastructure.

This new procedure includes the implementation of standardised forms, timelines, and information requirements which will make it easier for EV charging providers to deploy chargers in all regions of the province.

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“As the number of EV owners in Ontario continues to grow, our government is making it easier to put shovels in the ground to build the critical infrastructure needed for drivers to charge their vehicles where and when they need to,” said Todd Smith, minister of Energy.

“This is just another step we are taking to reduce red tape, increase EV adoption and use our clean electricity supply to support the electrification of Ontario’s transportation sector.”

This initiative is part of the government’s larger plan to support the adoption of electric vehicles and make EV charging infrastructure more accessible, which includes:

• The EV ChargeON programme – a $91 million investment to support the installation of public EV chargers outside of Ontario’s large urban centers, including at community hubs, Ontario’s highway rest areas, carpool parking lots, and Ontario Parks.
• The Ultra-Low Overnight price plan, which allows customers who use more electricity at night, including those charging their EV, to save up to $90 per year by shifting demand to the ultra-low overnight rate period when provincewide electricity demand is lower.

Environmental assessment (EA) process

One of the changes to the EA process is moving to a project list approach, which will list the types of infrastructure projects that still require the highest level of environmental assessment such as large landfills and electricity generation facilities.

The project list approach is a shift from the previous focus on project proponents to what the project is and its potential for environmental effects. Using a project list approach is meant to bring Ontario in line with other similar jurisdictions, including the federal government, Quebec and British Columbia.

The Ontario government noted that the comprehensive EA process for the East-West Tie Transmission Project that runs from Wawa to Lakehead in Northern Ontario took more than five years to complete.

With these changes, it said, a similar project could follow a streamlined process and be completed within two years, while still undergoing a mandatory consultation process and continued environmental oversight. Some of the time savings are a result of the streamlined processes not requiring a Terms of Reference, lasting up to two years, for the project as the streamlined process already sets out the requirements.

The government is also considering a minor change to the Environmental Assessment Act that would make it clearer for municipalities, provincial ministries and agencies that expropriation is one of the ways property can be acquired for a project before the EA process is completed.

Originally published by Sean Wolfe on, and edited with permission from, Power Grid.

The new organisation, which is expected to be launched in the Summer of 2024, will be an independent public corporation responsible for planning Britain’s electricity and gas networks and operating the electricity system.

It will be tasked with ensuring that Britain’s energy system is secure and affordable and forging the path to a sustainable future for everyone through its role in coordinating across the whole energy system and considering the connections between energy vectors and their relationship with the wider system.

“We’re delighted and excited to reach a key next step in our journey and to introduce the identity of this new organisation, National Energy System Operator, which will be at the heart of the whole energy system,” commented Fintan Slye, Executive Director of National Grid ESO.

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“We are continuing to deliver on our core role of energy security, affordability, and sustainability as ESO today, and to transform elements of the business to ensure we are ready to take on new accountabilities as the National Energy System Operator later this year.”

The ‘future system operator’ and its role was established in Britain’s Energy Act 2023, following a consultation that determined the need for a ‘whole system’ approach to the energy markets, including both the existing electricity and gas systems as well as future emerging markets of hydrogen and carbon capture and storage, to deliver on the net zero goals.

The outcome of the consultation was that the body should also be independent of asset ownership and other commercial energy interests, and from day-to-day operational control of the government.

Up to then the electricity and gas system operators were owned by National Grid.

The new scheme sees the National Energy System Operator founded on the National Grid ESO with the addition of new responsibilities, while the former National Grid Gas, now National Gas, continues as the owner and operator of the national gas network.

The company through its subsidiary National Gas Metering maintains and manages around 6.8 million domestic, industrial and commercial combined gas assets, while National Gas Services provides pipeline repair, maintenance and intervention.

Akshay Kaul, Director General for Infrastructure at Ofgem, said: “We’re pleased to see the Future System Operator come one step closer to reality with this new name and identity, which underlines the instrumental role it will play as an independent, expert organisation tasked with guiding Britain’s transition to net zero.

The year 2023 was a record-setting year for investment and growth in clean energy, with the International Energy Agency projecting over 500GW of new renewable capacity to come online by year-end globally. Energy storage, a critical component of a fully renewable grid, also saw record growth in 2023 and Bloomberg New Energy Finance has forecast a 27% compound annual growth rate to 2030 to enable renewable growth.  

These trends were supercharged at COP28, where over 100 countries committed to a tripling of renewable energy capacity by 2030. As these bold commitments trickle down to the state and local level, specific policies and roadmaps will emerge to accelerate the deployment of wind, solar and energy storage technology. 

These policies and roadmaps will not be developed in a vacuum. The world at the end of 2023 is an increasingly challenging one, with geopolitical instability, lingering supply chain uncertainty and broader concerns for global environmental justice influencing policy and investment decisions.

These considerations will shape the growing clean energy sector as countries seek solutions that reduce carbon emissions, increase energy security, and ensure environmental sustainability and economic opportunity for their citizens.

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Looking ahead to 2024, we anticipate:  

Concrete policy commitments for clean energy deployment 

In 2024, countries will promulgate specific plans and targets to accelerate policy momentum and achieve the ambitious targets set at COP 28. In the United States, the Inflation Reduction Act is already providing substantial funding for new clean energy projects at the federal level while individual states set ambitious deployment targets. Just last month, the state of Michigan set an energy storage deployment target of 2,500 MW by 2030, joining 10 other states with concrete storage targets. 

This is not limited to the U.S. In Australia, the government of New South Wales has set a goal of 2 GW of long-duration energy storage installed by 2030, and the state of Victoria is committed to 2.6 GW of storage online by 2030. Similar targets are being implemented or considered in Europe and elsewhere globally. In 2024, the race to set and achieve bold clean energy targets will intensify.

Energy security will remain centre-stage

Following the Russian invasion of Ukraine in 2022, energy security became one of the top considerations of policymakers, energy companies and consumers worldwide. Instability in global oil markets served as a reminder of the risks associated with reliance upon globally traded energy commodities controlled by a small group of countries.

Fortunately, an economy powered by renewable energy is potentially much more secure and resilient than one reliant upon fossil fuels. As the clean energy transition accelerates, expect that policymakers will pay close attention to both security of energy supply and security of technology supply: 

• Security of energy supply: Decentralized energy generation reliant upon wind and solar energy is inherently more resilient than large-scale, centralized power grids. In 2024, deployment of these decentralized models will accelerate as utilities and regulators continue to see the advantages. For example, ESS technology is powering a solar + storage microgrid at an industrial recycling facility in Pennsylvania which enables the company to operate seamlessly during grid outages, while also significantly reducing carbon emissions.  

• Security of technology supply: Chokepoints in the global clean energy supply chain are beginning to emerge. Today, energy storage = lithium-ion and the supply chain for lithium-ion batteries runs through a small number of countries, creating supply chain risks. In contrast, new alternatives such as iron flow battery technology, are able to leverage broad supply chains thanks to Earth-abundant materials and commonly available components, mitigating supply chain security risks.

The security advantages of renewable energy will continue to shape energy policies and accelerate the clean energy transition in 2024. 

Circular economy principles will factor into decision making 

In addition to security considerations, in 2024, the environmental, social, and economic impacts of clean energy technology will increasingly factor into procurement decisions. Growing attention to resource and carbon-intensive supply chains and concerns about end-of-life disposal will favour technologies with superior environmental profiles over those which require intensive mining, manufacturing and recycling processes. 

Emerging iron-based energy storage technologies offer one example of an inherently more sustainable alternative. Earth’s abundant materials and commonly available mechanical components can be readily recycled or repurposed at end of life. Additionally, iron flow batteries have approximately one-third the carbon footprint of Li-ion technology, further reducing sustainability risks.  

Emerging technologies will come of age 

In response to these broader trends, over the next year, new clean energy technologies will become established and grow from megawatt-hour to gigawatt-hour scale.   

This trend is already beginning. In Australia, ESS technology will enable the retirement of large coal-fired power stations. An initial iron flow battery pilot project is currently being developed at the Stanwell Power Station in Queensland, Australia, to be followed by a 150 MW installation with options for a further 200 MW per year beginning in 2026.

In Europe, the continent’s largest clean energy hub is in the early stages of development by LEAG, a major German energy generator. When complete, the hub will include 7-14 GW of renewable generation paired with 2-3 GWh of long-duration energy storage to provide green baseload energy and effectively replace coal generation. ESS is partnering with LEAG to supply the long-duration storage component and engineering work is already underway, with delivery of the first 500 MWh iron flow battery system expected in coming years.  

Going forward, these early large-scale projects will provide a blueprint for the clean energy transition and demonstrate how to deliver resilient, clean, baseload energy without fossil fuels.

2024 promises to be an exciting year in the clean energy industry as commitments from COP take shape and renewable deployments accelerate. At ESS, we look forward to continuing to build and deliver safe and sustainable long-duration energy storage solutions and working with our partners to deliver the paradigm-shifting projects which will be the blueprint for the clean energy future.

About the author
Eric Dresselhuys is the CEO of ESS Inc. and joined the long-duration energy storage company in 2021. Dresselhuys has over 25 years of leadership experience and is an accomplished technology and market development pioneer with a demonstrated background in growing both public and private companies.

The initiative, supported by national funding, involved 12 utilities in six provinces across the country serving almost 7.5 million customers – almost half of the electricity customers – to benchmark efforts and progress with decarbonisation with the implementation of a smart energy system.

The project, led by Network member Dunsky Energy + Climate Advisors, was based on a scorecard developed with 13 metrics with more than 140 indicators to assess progress in three categories or ‘core goals’ – cleaning the energy supply, transitioning to a modern grid and enabling customers and society goals.

Based on these scores, it emerged that all of the utilities were involved in the decarbonisation process but at varying stages, with each demonstrating leadership in one or other of the metrics and indicators.

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While none were recorded as ‘aspirational’ with high scores across all metrics, three were identified as ‘top performers’, while the majority were in the middle as ‘moderate performers’ – in many cases, their actions constrained by the boundaries of their regulatory or policy environment.

In general, the larger utilities were found to score more points, with their greater financial and non-financial resources to plan, execute, innovate and adopt best practices.

However, some small utilities outperformed their larger peers due to a combination of local innovation, jurisdictional opportunities and leveraging external funding sources.

The state of the grid and nature of ownership also influenced the scores with e.g. crown corporations and municipally owned utilities being organically aligned with government and community objectives in the ‘Customers and society’ category.

Capability maturity model

With this data, the second phase of the project involved the development of a ‘Capability maturity model’ for utilities to use to self-assess their capabilities and progress towards smart energy objectives and decarbonisation.

The model, the development of which was led by Siemens Canada with a subset of seven of the 12 participating utilities, is structured with three dimensions – objectives, business capabilities and the applications that are needed.

Key insights that were reported for this phase are that size matters and policy direction is a significant driver.

The large vertically integrated utilities typically have a greater scope of service as well as regulatory constraints which can mean larger hurdles to overall capability maturity. Moreover, the dimensions and interdependencies between business groups within a larger organisation can increase the effort and significantly challenge change management enablement.

Similar to the size of the utility, the influence of government and regulatory policy has a greater impact on the priorities and constraints of larger, vertically integrated utilities. This can significantly influence how the utility prioritises grid modernisation and business transformation activities.

Commenting on the whole initiative Greg Robart, CEO of the Smart Grid Innovation Network, said: “As intense electrification becomes more and more important as a decarbonisation strategy for Canada, the key actors in the electricity sector will carry a lot of the responsibility for Canada’s ability to meet its net zero targets.

“We are proud to be part of this important benchmarking project in collaboration with Dunsky, Siemens and the University of New Brunswick to build out Canada’s first scorecard.”

Moreover, almost two-thirds believe that green skills shortages could become a bottleneck and slow down the transition.

But only just over half of them are implementing or planning to implement such programmes for their workforce.

“Without skilled workers, the transition will not be delivered, and the benefits will not be realised,” says Ignacio Galán, Executive Chairman of Iberdrola.

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“As the world emerges from COP with a clear focus on phasing out fossil fuels, as well as tripling renewables in six years, every company in every sector is fully aware that change is coming fast.”

He adds that those who plan well “will lead and be at the forefront of the transition”, referencing activities by Iberdrola including helping aeronautics companies to take the lead in wind power, shipbuilders to diversify into offshore wind fabrication and oil and gas workers to switch to offshore renewables.

The survey involved 1,000 business leaders globally from the energy and utilities sector as well as the IT and technology, construction and infrastructure and transport and logistics sectors.

The data indicates that participants were overwhelmingly optimistic about the green transition and felt that it would create more and higher quality jobs than it would eliminate.

It also will require all workers to acquire green skills, both non-vocational, non-technical and of a more technical, role specific nature.

Among those in the former category the top three were identified as environmental awareness, innovation and creativity and problem solving, while the latter includes sustainability and disclosure reporting, environmental impact assessment and sustainability compliance.

In the energy sector, over one-third identified smart grid implementation as one of the most important green skills to enabling their organisation’s green transition.

Leading the transition

The survey found that two-thirds of the business leaders feel responsibility for leading the green transition lies with them over policymakers.

However, bridging emerging skills gaps will require coordination between the private sector and government and educational institutions.

The top three government policy priorities identified are support for businesses’ investment in up-skilling and re-skilling programmes, support for the establishment of green skills courses at educational institutions and adapting existing work and training programmes for the unemployed to increase the emphasis on green skills.

In addition, it is suggested that in the longer term governments will need to create an enabling environment that incentivises the greening of the economy more broadly with e.g. stricter standards, putting a price on emissions and removing subsidies for polluting industries, such as fossil fuels.

Through a memorandum of understanding with the government-led National Digital Twin Programme, the two parties intend to collaborate to ensure there is alignment and interoperability between the energy system data sharing infrastructure and the latter’s cross-sector integration architecture that is under development.

The initial focus is on developing an integrated high level technical design and architecture identifying the interfaces between components of the future energy system data sharing infrastructure.

It also aims to scope the technical, process and policy requirements for achieving and developing an integrated minimum viable product that both programmes can use to practically demonstrate connected digital twins.

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“We are excited to sign this Memorandum of Understanding with the National Digital Twin Programme to look at the components for developing an energy sector data sharing infrastructure,” commented Shubhi Rajnish, Chief Information Officer at the ESO.

“This collaboration is a significant step for energy digitalisation and the goal of enabling secure and resilient exchange of data across the sector, to support the delivery of a zero carbon energy system in Great Britain by 2035.”

National Grid ESO’s Virtual Energy System programme has the ambition to enable the creation of an ecosystem of connected digital twins of the entire energy system of Great Britain, operating in synchronisation to the physical system.

It is proposed to include representations of electricity and gas assets and link-ups to other sectors to enable secure and resilient sharing of energy data across organisational and sector boundaries and in turn to facilitate complex scenario modelling to deliver optimal whole-system decision making.

The programme was launched in December 2021 and in March 2022 National Grid ESO was awarded funding to develop the principles and a technical framework, which was undertaken with Arup, the Energy Systems Catapult and Icebreaker One.

Since November 2022 a common framework demonstrator has been under development, which is planned for showcasing the benefits during the current year.

Various investigations and recommendations in Britain have focussed on the need for energy sector-wide data sharing, as indeed they have with the focus on digitalisation elsewhere and in other sectors.

The National Digital Twin Programme, led by the government’s Department for Business and Trade is aimed to grow national capability in digital twin technologies with its primary purpose to develop the standards, processes and tools that will build the foundation of a functioning market in digital twins.

The ‘cap and floor’ proposal is conceptually similar to that developed by Ofgem and currently in operation to enable investment in electricity interconnectors.

In this case, the regime provides a minimum revenue certainty for investors, i.e. the floor, to provide debt security and a regulated limit, i.e. the cap, on revenues to avoid excessive returns.

When revenues fall below the floor level, they are topped up by consumers through the financing mechanism. Conversely, when revenues breach the cap, excessive returns are passed on to the consumer.

“A cap and floor scheme would unlock investment from private sources by providing a revenue guarantee, giving investors reassurance that they will receive a return on their stake, as has been demonstrated in the interconnector scheme,” states a consultation document from the Department for Energy Security and Net Zero (DESNZ).

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“Unlike the capacity market approach, this is potentially a low-cost option if the floor is met and no top-up is provided (the case with the interconnector model to date). It is also expected to reduce the weighted average cost of capital for projects by reducing the overall investment risk, which is particularly important in addressing the high upfront costs associated with developing long duration energy storage and overall system costs.”

The consultation, which runs to March 5, is aimed to seek input on design options for the cap and floor scheme, including considerations on how it is delivered and on how the associated risks are mitigated.

Among these is a proposal to split the scheme into two ‘streams’ – one for established technologies, i.e. pumped hydro storage, liquid air electricity storage, etc., and a second for novel technologies, e.g. compressed air electricity storage, flow batteries, etc. – to allow tailoring to overcome specific barriers and best support the respective technologies.

Long duration energy storage scenario

Alongside the consultation, the DESNZ has also published a deployment analysis of long duration energy storage (LDES) – defined as a capacity of at least 6 hours – which was commissioned from energy transition consultants LCP Delta and Regen.

A key finding is that modelling shows that adding LDES to the system can have a positive impact on both emissions and system costs, with the duration of the deployed storage being the biggest factor in the size of that impact.

For example, adding just 3GW of LDES in 2035 is modelled to reduce power system emissions intensity by 3-8%, while 12GW of LDES could reduce the emissions intensity by 10-28%.

Another top level finding is that the capital costs of LDES technologies are critical in determining their net benefits and at medium capex levels, most technologies tested bring net benefits to the system.

With the ‘optimal’ deployment level depending on the type of LDES technology, with the benefits of different technologies peaking at different points, both the technology type and duration are important in determining the scale of system cost reduction.

Another finding is that LDES can act as a risk mitigation for reduced delivery of other technologies. With lower levels of gas carbon capture and storage and hydrogen deployment, there are greater emissions and system cost benefits when LDES is added to the system.

However, the location of the LDES was found to not be a significant driver of the benefits to the system, with such benefits significantly smaller than the overall benefits of adding LDES to the system.

Overall, LDES technologies could have a significant impact on providing the flexibility the future GB power system will need, the report concludes.

With the capital costs for LDES technologies an important driver of the extent of system benefits, the reduction of these costs should be a key focus and will help bring these technologies to market.

Originally published on powerengineeringint.com

In the analysis ICRA states that the pace of installations is expected to witness a significant jump over the next two years, supported by the progress in tendering and the government’s focus on improving the finances of the distribution companies.

As of December 2023, 222.3 million smart meters had been sanctioned by the government, but of these 98.7 million had been awarded.

However, only 8 million smart meters had been installed as of December 2023.

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The Revamped Distribution Sector Scheme was introduced by the government in July 2021 with the objectives of improving the financial and operational efficiencies of the distribution companies, including reducing the aggregate technical and commercial losses to 12-15% by 2025 – a target not far off being reached in 2023, the Ministry of Power has reported.

A key pillar of the scheme is the nationwide rollout of smart meters, with the adoption of a ‘design, build, finance, own, operate and transfer’ model to enable the distribution companies to avoid the upfront investment cost of the meters and associated communication and IT infrastructures.

Advanced metering infrastructure service providers, who supply, finance, install and operate the systems, then bid for the projects, with the service charge per month per meter being the key parameter, ICRA notes.

ICRA also comments that the viability for the winning bidders remains largely linked with the capital costs of the smart meters and their associated infrastructure.

Further, the availability of a direct debit payment mechanism, wherein online payments received from consumers are routed from the payment gateway to the AMI service providers is likely to mitigate the counterparty credit risk associated with the distribution companies to a large extent.

However, demonstration of this mechanism remains to be seen.

ICRA states in the analysis that the expected jump in smart meter installations over the next two years should improve the billing and collection efficiency of the distribution companies.

However, it advises that while choosing customers for replacing the meters, the companies should be mindful of their consumption potential to achieve net positive savings after the installation.

Among the rollouts under way, the state smart metering jv Intellismart has an order book of approximately 20 million units.

Similarly Adani Energy Solutions has an approximately 20 million smart meter order book and is partnering with telecoms provider Airtel, which will power them with its IoT platform based on NB-IoT, 4G and 2G.

The three suppliers are EDF, Octopus Energy and Scottish Power, which have been authorised as meeting the conditions and further must follow a comprehensive set of new rules.

A moratorium on the practice was introduced in February 2023 after complaints on the practice, including forced entry by court warrant, and in particular that it was being used against vulnerable people.

Under the new rules, the three suppliers are able to install a prepay meter involuntarily as a last resort having met certain conditions.

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These include conducting an internal audit to identify wrongfully installed involuntary prepay meters prior to the moratorium and offering compensation and a return to a non-prepayment payment method to any affected customers and completing an independent assessment to verify their readiness to comply with the new rules.

Once the involuntary installations have restarted the suppliers also must provide regular monitoring data to Ofgem.

In addition, if a supplier installs a prepay meter in a property occupied by someone in the ‘do not install’ category set out in the licence conditions and have not followed the rules to make sure a prepayment meter is appropriate, they are expected to reinstate a credit meter within 24 hours and compensate the customer appropriately.

“We’ve made clear that suppliers must exhaust all other options before considering forced installation of a prepayment meter, and consumers can help themselves by reaching out to their supplier as soon as possible if they think they won’t be able to pay their bill, so payment options can be discussed,” said Tim Jarvis, Director General for Markets at Ofgem.

“While nobody wants to see the practices uncovered last year repeated, we also know that allowing households to build up unsustainable amounts of debt isn’t the right thing to do either. Many households value the control that these pay as you go meters offer over bills and how they can help with budgeting, and suppliers must also be able to recover debt to make sure those costs don’t end up on everyone else’s bills.”

New rules for suppliers

Among the new rules put in place by Ofgem prior to an involuntary installation, suppliers must have made at least 10 attempts to contact the customer and carried out a site welfare visit.

They also must refrain from involuntary installations for the highest risk customers (the ‘do not install’ category) including households which require a continuous supply for health reasons, those with an older occupant aged 75+ without support in the house, those with children aged under 2 years old, and those with residents with severe health issues including terminal illness.

In other cases including children aged 5 years and serious medical or mental health conditions as well as temporary situations such as pregnancy or bereavement, the suitability of a prepay meter must be assessed prior to installation.

Under the new rules suppliers are required to contact customers if they miss two monthly or one quarterly payment, check to see if they are struggling with bills and if so, offer support such as affordable payment plans or repayment holidays.

Suppliers will also be required to publish the Citizens’ Advice ratings of their customer service so consumers can see how they compare on issues such as call wait times and quality of responses.

Ofgem has reported that the announcement also comes on the back of updated bad debt levels from the end of last year, which showed that the pause in fitting some prepay meters had been part of the contribution to the highest levels of energy debt ever, currently estimated at around £3 billion (US$3.8 billion).

Commenting on the announcement, Dhara Vyas, Deputy Chief Executive of Energy UK, said that involuntary installations are a last but necessary resort for cases where repeated attempts to address debt with the customer through other means have been unsuccessful.

While suppliers have a responsibility to try and prevent customers falling further into arrears as well as limiting the build-up of bad debt, the new and extended exempt categories and the pause itself mean that customer debt will inevitably increase.

“It underlines the need for the government to put in place targeted support for those customers most in need to help make bills more affordable and stop the build-up of debt in the first place.”

Through the recommendations, the NDRC calls on the establishment of a technical standard system for vehicle-to-grid (V2G) interaction by 2025, by when charging peak and time-of-use electricity prices should be fully implemented.

The specific reform recommendations include:

1. Promote research on core technologies of V2G interaction, by:

• Increasing efforts to research key technologies for power batteries
• Developing a reliable, flexible and low energy consumption V2G interaction system architecture and bidirectional charging and discharging equipment
• Researching key technologies for grid-friendly charging and battery stations, as well as technologies for accurate prediction and aggregated control of distributed V2G interaction
• Strengthening research on key technologies for V2G interaction information exchange and information security.

2. Accelerate the establishment of a V2G interaction standard system, by:

• Developing and revising national and industry standards related to V2G interaction
• Formulating and revising key technical standards for charging and discharging equipment and technical specifications, vehicle-pile communications, grid-connected operation, two-way metering, charging and discharging safety protection, information security and other key technical standards in two-way charging and discharging scenarios by the end of 2025
• Improving the standard supporting testing and certification system while promoting the implementation of intelligent and orderly charging standard requirements in vehicle production access and charging pile production, installation and acceptance.

3. Optimise supporting electricity prices and market mechanisms, by:

• Encouraging the formulation of independent peak-valley time-of-use electricity price policies for charging facilities with strong load guiding capabilities
• Fully applying residential peak-valley time-of-use electricity prices for charging by the end of 2025
• Studying and exploring the pricing mechanism for the discharge of EVs and charging stations to the power grid.
• Establishing and improving V2G interactive resource aggregation to participate in demand side management and market transaction mechanisms
• Encouraging bidirectional charging and discharging facilities to participate in pilot demonstrations of the power market through resource aggregation.

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4. Carry out demonstrations of two-way charging and discharging models that integrate new energy vehicles, by

• Encouraging power grid enterprises to jointly carry out two-way charging and discharging pilot projects with charging companies, vehicle companies, etc. in residential communities.

5. Improve the interaction level of battery charging and swapping facilities, by:

• Promoting intelligent and orderly charging facilities
• Establishing and improving the smart and orderly charging management system and process for residential communities while clarifying the responsibilities and rights of power grid companies, third-party platform companies, new energy vehicle users and other parties
• Encouraging power grid enterprises to cooperate with charging operators to establish an efficient interaction mechanism
• Exploring and studying power access capacity assessment methods and related standards and specifications for different types of intelligent and orderly charging and swapping facilities
• Encouraging charging operators to build integrated PV, storage and charging stations according to local conditions to promote the integrated development of transportation and energy.

6. Systematically strengthen support capabilities of power grid enterprises, by:

• Incorporating V2G interaction into power demand side management
• Supporting power grid enterprises to carry out V2G interactive management in combination with new power load management systems
• Improving power grid demand side management and power regulation platform functions to provide basic support and technical services for V2G interactive aggregation transactions
• Accelerating the improvement of V2G interactive supporting grid connection, metering, protection control and information exchange requirements and technical specifications
• Optimising power grid clearing and settlement mechanisms and supporting V2G interactive load aggregators to directly participate in the clearing and settlement of the power market.

According to research from the International Energy Agency, in 2022, China accounted for 60% of global electric car sales, maintaining its dominance in the sector.

They add that more than half of the electric cars on roads worldwide are now in China, with the country already exceeding its 2025 target for new energy vehicle sales.

And with the increase in EV uptake, demand will continue to rise similarly on the power grid, necessitating better integrated V2G planning.

Through the announcement, the NDRC stated they will work alongside the country’s National Energy Administration and relevant departments to implement the above reform recommendations.

Under the proposal, first announced in 2020, Avangrid would have acquired PNM Resources and its two utilities — Public Service Co. of New Mexico and Texas New Mexico Power.

The all-cash transaction was valued at more than $4.3 billion and would have opened the door for Iberdrola and Avangrid in a state where more wind and solar power could be generated and exported to larger markets.

The utilities said the merger would have brought more than $300 million in benefits to PNM customers. PNM had argued the merger would provide it greater purchasing power to help move it closer to its carbon-free goals.

But the New Mexico Public Regulation Commission rejected the proposal in 2021, citing concerns about Avangrid’s reliability and customer service track record in other states where it operates. PNM Resources then filed a notice of appeal with the New Mexico Supreme Court.

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Avangrid said the group needed to receive approval for the merger from regulators by the end of 2023. The company said Dec. 31 was the date that either Avangrid or PNM could terminate the merger agreement if it had not yet been finalized.

“There is still no clear timing on the resolution of the court review of the New Mexico regulator’s denial of the merger nor any subsequent regulatory actions,” reads an Avangrid company statement in-part.

“While our merger agreement with PNM has been terminated, we remain more than ever steadfast in our commitment to New Mexico in the development of wind and solar renewables, helping explore options in the new hydrogen economy, and delivering on the partnership with the Navajo Nation to achieve its clean energy future,” the company said.

PNM Resources said its Board of Directors had approved an extension beyond Dec. 31 that was not accepted by Avangrid.

“We are greatly disappointed with Avangrid’s decision to terminate the merger agreement and its proposed benefits to our customers, communities and shareholders,” said Pat Vincent-Collawn, PNM Resources Chairman and CEO. “As we move forward, our strategic plans remain focused on the infrastructure investments necessary to meet the future energy needs of our customers and communities.”

Originally published in Power Engineering.

The assessment, compiled as a statutory requirement annually, quotes 2021 smart meter data as the latest, with numbers of 111.2 and 115.3 million smart meters from the EIA and Institute for Electric Innovation respectively.

These correspond to respective penetrations of 68.3% and 70.8%, based on a total of 162.8 million metering endpoints in the US.

That year also was the fifth consecutive year that the number of advanced meters has increased by approximately 8 million.

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In that year also for the first time the penetration in each of the customer classes rose over 60%, reaching 68.7% for the residential, 65.6% for the commercial and 63.2% for the industrial classes.

The data also is broken down by census division with the highest penetration of 86.2% recorded in the West South Central division, i.e. Texas, Oklahoma, Arkansas and Louisiana.

Other divisions with penetrations exceeding 70% were the East North and East South Central, Pacific and South Atlantic – this latter experiencing the largest increase in smart meters in the year with utilities including Virginia Electric & Power, Duke Energy Florida and Appalachian Power reporting just over 2 million more meters or 9%.

Conversely the lowest penetration, just 23.1%, was recorded in New England, which includes the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont, while the Middle Atlantic, including New York, New Jersey and Pennsylvania, was at 40.7%.

Overall the West North Central division recorded the largest percentage increase of 14%, allbeit from a low base, with utilities reporting approximately 770,000 more smart meters.

The Institute for Electric Innovation has most recently projected 128 million smart meters to be installed in the US by the end of 2023 with the penetration approaching 80%.

Demand response assessment

The assessment finds that from 2021 to 2022, the demand response resource capacity in US wholesale markets increased by approximately 817MW to a total of 32,920MW, representing a 2.5% increase.

Demand response resource totals increased from 2021 to 2022 in all but one of the wholesale markets. Despite this increase in the capacity of demand response participating, the percentage of peak demand that these resources represent fell slightly from 6.6% in 2021 to 6.5% in 2022 because the increase in peak demand outpaced the increase in demand response.

Utilities and system operators in certain parts of the country also are increasingly evaluating opportunities to use load flexibility, as facilitated by the deployment of customer-sited distributed energy resources and other energy management devices, to help address the needs of a system with a growing penetration of variable energy resources.

For example, California recently established a statewide goal to develop 7,000MW of load flexibility resources to reduce net peak electrical demand.

State regulators and utilities also continue to consider the advantages and disadvantages of different types of time-varying retail rates, especially in the context of integrating electric vehicles (EVs).

With an additional 112GW of capacity already installed, the 139GW this action plan delivers exceeds the 225GW needed to decarbonise the grid, states ENA.

The action plan report, Rising to Britain’s Net Zero Challenge: Our fairer and faster connections action plan, confirms that thanks to the pace of progress seen since the start of 2023, nearly 50GW of additional capacity is already available to customers.

The report explains six steps in the energy networks’ action plan, four of which have been under way since the start of the year and two that are new. 

The four steps that already under way include: 

1. Release up to 90GW of capacity by cleaning up the queue and actively managing a “first ready, first connected” process. 
2. Accelerate up to 70GW of applications by allowing some applicants to connect faster, before enabling works are completed.
3. Release nearly 3GW of capacity by treating storage projects, which are increasing faster than any other technology – up 5,930% from 2019-2023, differently. Network operators are changing the modelling and assumptions for storage projects at both transmission and distribution level, to better align with actual usage patterns.
4. Release 46GW of capacity by making network planning processes more coordinated and realistic. Improved construction planning assumptions, and a reformed transmission connections framework will allow for a more efficient process that is not hindered by high application volumes and customer attrition from the queue.
   
   The two additional steps that complete the action plan are: 
   
5. Strengthen and tighten the application process by making the process more discerning – providing more information to the market, requesting more data from applicants and standardising pre-application engagement.
6. Further improve coordination between transmission and distribution operators, including reviewing the threshold for referral for transmission impacts, improving transmission to distribution data exchanges and reforming transmission asset charging methodologies for distribution customers.

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These six steps build on reforms that are already under way across the industry including the ESO’s Five Point Plan, Ofgem’s initiative to reform connections rules and ENA’s Strategic Connections Group Action Plan announced earlier in the year. 

Through the ENA, the report calls on the need for planning, land rights and consenting reforms to speed up the building of new infrastructure. The report also calls on government and Ofgem to work with industry to make improvements to how ‘the queue’ is accessed and prioritised.

Network operators currently have an obligation to offer connection agreements to any project, regardless of technology or the project’s viability. 

Lawrence Slade, ENA chief executive, commented on the grid capacity action plan in a release:  “We need to pull out all the stops to accelerate and improve grid connections and this plan gets us the capacity we need in just one more year to decarbonise the grid.

“The industry action plan we’ve set out today includes new ways to strengthen and tighten up the application process for connections to ensure only projects with a realistic chance of coming to fruition are approved, as well as a redoubling of efforts to improve coordination between transmission and distribution operators which we know will be more streamlined and ultimately, fairer for customers.

“Uptake of the benefits outlined by ENA will depend on the ability of the market to progress projects, including the number of projects which are in the current queue but turn out to be not viable. These so-called ‘zombie projects’ take up valuable capacity in the queue which could be released for other projects which are viable and ready to connect.”  

External financial support is generally only required for energy communities until two regulatory-related conditions are met.

One is that the red tape surrounding the establishment and operation of energy communities is reduced to the level of accepting terms for a digital app, with local service providers offering turnkey solutions for renewable energy installations and asset management.

The second is that the scope of energy community trading is extended to peer-to-peer trading within and among communities, which is permitted by the related EU directives but not yet by the member state implementation of these.

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Maximising benefits for local energy communities

The new study, which was conducted by Grid Singularity in collaboration with the Fraunhofer Institute of Applied Information Technology (FIT) and published by the German Energy Agency dena, confirms this perspective.

The study, titled ‘The decentralised energy system in 2030. A systemic bottom-up approach to market integration of decentralised consumption and generation assets’ (‘Das dezentralisierte Energiesystem im Jahr 2030 – Ein systemischer Bottom-up-Ansatz zur Marktintegration dezentraler Verbrauchs- und Erzeugungseinheiten’), received support from the German Federal Ministry for Economic Affairs and Climate Action (BMWK).

Bottom-up approach to market integration

In the study a bottom-up, agent-based model of the German energy market was simulated, with 967 agents representing distributed energy assets (PV, electric vehicles, heat pumps, battery storage, consumption load profiles, wind power plants) and their owners’ trading preferences in a possible German electricity system in 2030, with our open source Grid Singularity Exchange software tool for simulating and operating local, regional or national energy markets.

The number and the regional distribution of the respective agents were determined by our research partner, FIT, which based its calculations on the German Market Master Data Register and the German government’s forecasts for distributed energy resources (DER) expansion for 2030 (Bundesministerium für Wirtschaft und Klimaschutz, 2022 and 2023, Bundesnetzagentur, 2022).

The study envisaged the German electricity market in 2030 as one that is composed of connected local electricity markets in the form of local energy communities (LECs) fully engaging in peer-to-peer trading.

The applied simulation model has three market levels and the trading is bottom-up peer-to-peer electricity trading (P2P), i.e. asset-based, moving up the market hierarchy, as follows: i) trading within the LEC, ii) trading within and among LECs in one region, and iii) trading within and among LECs across the entire country.

The market design follows the pay-as-bid spot market type, where bids and offers are matched hourly in a P2P exchange. Prices for matched trades are determined by market conditions, considering feed-in tariff rates and utility rates, accounting for grid costs and ensuring that any matching gap is supplemented by the utility.

The study investigated six simulation scenarios in addition to the base case scenario, researching the implementation of P2P trading at different market levels, with additional analysis of the impact of the time-variable grid fee and time-variable electricity price models.

In the study, we applied actual asset-to-asset (peer-to-peer) electricity trading among market participants which is in general compliance with the EU directives on energy communities, but still more advanced than the trading mechanisms currently applied in the EU, in particular in Austria and Spain, which are among the most progressive compared to other EU members.

These EU countries still allow only indirect intra-community trading with a single, predefined energy price and more correctly described as peer-to-market energy trading mechanisms. To this day, none of the EU members allow trading between communities and the study finds this to be a significant opportunity.

Key findings of Germany 2030 bottom-up market simulation

The analysis shows that the implementation of P2P electricity trading markets leads to an important reduction in electricity cost for the participating households and the industry. For households, the electricity bills would be reduced by 4% in the case of local, intra-community P2P implementation without inter-community trading and up to 20% if P2P trading is enabled across all communities and regions in Germany.

Participants in P2P electricity trading were able to purchase electricity from their peers at a lower price than from the utility, resulting in improved matching of electricity generation and consumption at the local, regional and national levels. Electricity cost savings progressively increased with the expansion of P2P electricity trading scope, from community alone to between communities in a region, finally resulting in a fully-fledged bottom-up energy market for the entire country.

Furthermore, the P2P trading scope expansion also brings about a momentous increase in the degree of autonomy, also termed self-sufficiency, which reflects the ratio of total demand satisfied by generation at the analysed market level (or differently put, the share of self-consumption in the total consumption).

The average self-sufficiency rate for the community rises from 6% in the base case scenario where self-consumption is limited to owners of renewable assets, to 31% with the activation of local P2P trading when these assets are effectively shared with other local energy community participants.

When P2P trading is scaled to inter-community trading at a regional level and then at national level, the average self-sufficiency rate for the region increases to a very high 70% and 73% respectively, effectively including wind generation and industry consumption in P2P market trading.

In conclusion, the study indicates that over two-thirds of the electricity demand of households and industry in Germany can be met with the country’s PV and wind generation by implementing a bottom-up P2P market design.

This outcome implies a significant relief of the transmission grid use but can also lead to a higher utilisation of the lower grid levels, and the implications for grid network planning and operation can be a subject of further research.

At the same time, the results show no significant impact on electricity costs, emissions or self-sufficiency when time-variable electricity prices and grid charges are introduced, which may be due to limitations of the modelled asset configuration and/or selected time of use grid fee model.

Notably, in the simulated model of the German energy market in 2030, battery storage is the only modelled energy asset that offers flexibility and responds to the corresponding price signals, providing benefits exclusively to owners of these assets and increasing electricity costs for inflexible consumers when time-variable electricity prices are introduced.

In order to take advantage of dynamic grid fee models, the flexibility in the system must be increased, rewarding those that invest in renewable and especially flexible resources while providing a reasonable level of protection for inflexible consumers.

Recommendations for policymakers

The study concludes with the following recommendations for German and other European policymakers:

■ The EU directive on the regulation of energy communities should be advanced and implemented nationally, strongly considering enabling inter-community trading in addition to intra-community trading to unleash more benefits for citizens and the grid.
■ In line with the EU Digital Energy Action Plan, a framework for testing P2P electricity trading in demonstration projects should be created to demonstrate the benefits of energy communities and to define clear criteria for implementation in Germany.
■ Market platform models should be researched and developed to ensure holistic operation of P2P electricity markets, enabling the operational and regulatory framework to control, protect and settle financial transactions (effectively enlarging the current, more limited scope of community coefficient-based exchange).
■ The rollout of smart metering systems, enabling remote access to high resolution (at least 15 minute) submeter data for energy asset generation and consumption, is a prerequisite for P2P electricity trading as well as other flexibility and energy optimisation services and should be implemented quickly and worldwide.
■ To connect and integrate a broader level of market participants, additional digital technologies such as digital identities and corresponding, decentralised registers for machine identities of energy assets – ideally linked at EU level – are recommended. With the help of digital identities and data exchange concepts such as data spaces, granular time-based proof of electricity origin and distribution can be leveraged to issue and trade fully verifiable guarantees of origin and to enable a rapid transition of market roles (e.g. from self-consumption to ancillary services to trading markets and back to self-consumption). End-to-end digitalisation is an accelerator for implementing and enabling an efficient and secure operation of energy communities.
■ The penetration of flexibly deployable home energy storage systems envisaged for the future is not sufficient for time-variable tariffs to induce a global cost-reducing influence on the electricity price. To effectively reduce electricity prices, flexible operation of heat pumps and EVs is necessary across the board. Further studies could investigate which market share of flexible consumption units, such as heat pumps, should be achieved or how high the degree of flexibility of loads should be for variable electricity tariffs to contribute to a global reduction in electricity costs.

For more information, see the study (in German) and the longer article (in English) by Grid Singularity.

On November 29, ENLIT 2023 featured a panel on “Financing energy communities” inquiring about the fate of these novel energy markets post-public support. Ana Trbovich, cofounder of Grid Singularity and the Energy Web Foundation – both working on leveraging new technologies to accelerate energy transition, participated in the panel, together with Venizelos Efthymiou from the University of Cyprus FOSS Research Centre, Chris Vrettos from RESCoop European Federation of Energy Communities, Stoyan Danov from CIMNE Research Centre and Zia Lennard from R2M Solutions, with moderation by Arjan Haring of Seldon Digital.

With this agreement, the rules need now to be formally adopted by the respective parties and published to enter into force.

The key focuses of the new rules are to enable the uptake of renewable and low-carbon gases and to establish a market design for hydrogen in Europe.

The renewable gas uptake will be enabled by facilitating connection and access to the existing gas grid and allowing discounts to cross-border and injection tariffs for these gases.

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A certification system for low carbon gases, including hydrogen, is also established, with the aim to ensure a level playing field and consistency in assessing the full greenhouse gas emissions footprint of different gases and allow member states to compare and consider them in their energy mix.

The hydrogen market design agreement foresees a two-phase approach, before and after 2033.

In the ramp-up phase, a simplified framework will apply with clear visibility about the future rules for a developed hydrogen with provisions covering inter alia access to hydrogen infrastructures, separation of hydrogen production and transport activities and tariff setting.

A new governance structure in the form of the European Network of Network Operators for Hydrogen (ENNOH) will be established to promote a dedicated hydrogen infrastructure, cross-border coordination and interconnector network construction. It will also be responsible for elaborating specific technical rules.

A new long-term planning regime also is envisaged with national network development plans based on joint scenarios for electricity, gas and hydrogen.

Hydrogen and gas network operators will have to include information on infrastructure that can be decommissioned or repurposed, and there will be specific hydrogen network development plans to ensure that the construction of the hydrogen system is based on a realistic demand projection.

Another element of the framework is consumer empowerment and protection, with the revision mirroring the provisions already applicable in the electricity market, so that consumers will be able to switch suppliers more easily, use effective price comparison tools, get accurate, fair and transparent billing information, and have better access to data and new smart technologies.

“[The] deal will help Europe move away from fossil fuels and embrace cleaner solutions,” commented Kadri Simson, Commissioner for Energy.

“These new rules are vital not only to develop an internal market for renewable and low carbon hydrogen, but also to ensure these cleaner gases will contribute to the decarbonisation of the EU’s economy.”

The agreement on the package has been welcomed by the industry association GD4S, with Raúl Suárez, CEO of Spanish gas distributor Nedgia and GD4S President, saying: “We welcome the recognition of the crucial role for gas distribution grids to support the energy transition through increasing shares of renewable and decarbonised gases. GD4S and its members stand ready to contribute.”

Global electricity demand is expected to grow by 50% by 2040. The International Energy Agency (IEA) recently noted that one in five cars sold is now electric, up from one in 25 just three years ago.

The US and Europe have made enormous investments in clean energy as both a bulwark against climate change and a measure to ensure energy security in a volatile geopolitical environment. Wind turbines are rising in the North Sea and off the Atlantic coast.

Solar PV’s installed power capacity is expected to surpass that of coal by 2027, the IEA reports.

If we truly want to decarbonise, we can’t simply generate more renewable energy. All that new energy needs a place to go. Around the world, ageing grids are ill-equipped to handle this growing electricity demand, and most of the world’s electrical grids were not built to handle distributed energy resources (DERs), such as renewables.

To meet this challenge, the grids will need to modernise quickly, adopting new technologies to enable a digitised, bidirectional energy that can adapt in microseconds to the new variables that come with the introduction of renewables.

Governments and businesses must invest in grid modernisation on par with the investment in energy generation. The UN estimates that the world will need to invest $4 trillion a year until 2030 to reach net zero by 2050.

Money, however, won’t be enough. In the past five years, the pandemic, extreme weather and wars in Ukraine and the Middle East have challenged energy security and supply chain stability. To avoid disruption to the energy transition, it is essential to have a secure and resilient energy technology and resource supply chain. That will require governments and industry to rethink the regulatory and resource environment.

For example, the European Commission’s Critical Raw Materials Act, proposed in March, seeks to ensure a critical domestic supply of 34 crucial raw materials, including 16 strategic raw materials, such as lithium, nickel, graphite and aluminum. Notably, it simplified the permit procedure of strategic extracting projects, cutting some of the red tape that can delay projects and inflate costs.

The technologies exist that allow us to integrate renewable energy from multiple sources – solar, wind, water and hydrogen, – without sacrificing reliability. GE has already deployed these technologies in more than 150 countries. We – and our industry partners – can build the grid of the future and electrify the world with the right global investment and commitment.