The number and volume of renewable energy power purchase agreements remained stable last year thanks to corporate buyers turning to long-term PPAs to hedge against rising and volatile electricity prices. 

That’s the finding of a new report which reveal that while 2022 saw disclosed contracted volumes dip to 8.4GW – a 21% decrease from the 10.7GW signed in 2021 – the total number of PPA deals in Europe increased by 4.5%, with at least 161 deals, as compared to 154 the year before.

Corporate PPAs held the fort, accounting for 80% of the total deal count, and 83% of contracted volumes, in 2022.

Corporate PPAs contracted capacity grew by at least 20%, up to 7GW from the 5.8GW in 2021. The increase in corporate deal count was even more pronounced, with 129 deals signed, up 29% on 2021 when it was 100.

The figures are revealed in European PPA Market Outlook 2023, an annual report from Swiss company Pexapark, a provider of PPA price reference, enterprise software solutions and renewable energy advisory services. 

“The maturity of the PPA market shone through amid the European energy crisis and the resiliency it exhibited was remarkable to say the least,” said Luca Pedretti, Co-Founder and Chief Operating Officer of Pexapark.

“It’s fair to say that certain corporate procurement departments deserve awards for saving their companies from spiralling energy costs.” 

Managing energy risks

Report co-author Maritina Kanellakopoulou, Senior Insights Analyst at Pexapark, said 2022 was “a year of ‘shock therapy’ for renewables investors”.

“For those who were caught out by the market conditions – and equally for those who weren’t – the turmoil made it a necessity to better understand and manage energy risks.

Read now: EU gas market reforms focus on hydrogen

“According to a market survey we conducted, a hefty 65% of sellers and buyers stated that enhancing energy risk management capabilities is a priority. When drilling down to IPPs, this statement was made by 54% of such business type participants.” 

As analysed in the report, short-term futures contracts reached such punishingly high levels that many corporate procurement managers took the bold step to safeguard cashflow and production costs by jumping into long-term PPAs.

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Activity of corporate and industrial energy buyers increased substantially in 2022, as reflected by the rising prominence of industrial supply contracts in markets like Spain, which remains the largest market for PPAs in Europe. 

While IT firms continued to hold the top spot for contracted volumes, with 1.97GW procured across 14 deals, metals and mining came in an extremely close second place, with 1.95GW procured across 19 deals.

Aluminium company Alcoa was the largest single buyer in Europe and Spanish independent power producer Greenalia was the largest seller, thanks to its deals with Alcoa.

Extreme volatility and regulatory change

Pexapark noted that this successful activity, however, does not mask the profound impact of market volatility and regulatory change on the continent’s renewable energy business models.

It highlights how the European energy crisis created extreme volatility throughout 2022, with the most notable spikes in January and September, where volatility levels reached more than 230%.

Energy Transitions Podcast: Why a gas price cap could worsen the energy crisis

High market prices moved down the forward curve, creating the phenomenon of extreme ‘backwardation’ which led to a notable price disparity between short-term and long-term PPAs.

These conditions accelerated the shift towards short-term PPA agreements, as power producers moved to adopt more active energy trading strategies with a rising focus on short-term hedges. 

Indeed, as investors’ merchant appetite increased, certain financing deals were underpinned by short-term PPAs or no PPAs at all, especially those leveraging instruments such as flexible construction facilities, or all-equity short-term financing.

Baseload PPAs

By contrast, those without robust risk management in place for their long-term Baseload PPAs, found themselves exposed to a combination of high prices, decreasing capture factors and under-production, leaving a series of assets in significant financial distress, especially in the Nordics area. 

The report states that appetite for Baseload PPAs wavered in line with market conditions. The price shocks of 2022 threw a spanner in the works for further uptake of these PPAs outside a certain class of sellers, who may now have a further competitive advantage in providing the much-discussed ‘24/7 Green Supply’ capability to buyers.

Further uncertainty has been generated by ongoing regulatory changes across all major European energy markets.

In 2023, country-specific policy and regulation will continue to have a key impact on activity in respective markets.

Renewables players will be significantly more alert, making regulatory monitoring standard procedure, while incorporating revenue impacts on hedging decisions. 

According to Pexapark, 2022’s notable developments are catalysing the rise of the ‘next generation investor’ as manifested by the actions of leading IPPs and funds.

This investor is defined as “businesses equipping themselves with a range of advanced tools, including sophisticated data and analytics, investment management systems, and a risk management mindset applied to a diversified, hybrid portfolio consisting of wind, solar and storage assets across multiple price zones”.

The report concludes that such practice will strongly benefit the renewables market, and build resiliency and readiness to tap opportunities, whether there’s a pricing crisis or not. It is expected that this will be the ‘new normal’ heading into 2023.

Pexapark’s Top predictions for 2023 

1. The popularisation of short-term PPAs: Moving forward, managing renewable revenue with a mix of short- and long-term PPAs will become the norm. 

2. The evolution of the tripartite PPA: Project owners, utilities and corporates will join forces, leveraging each of their individual strengths and competencies to conquer the PPA market. 

3. The coming of age of Co-location and Flexibility:  Volatility and system costs will increase the share of renewables-plus-storage and bring to the fore PPAs reflecting both energy sale and storage elements. 

The post ‘Shock therapy’ spurs the rise of next generation renewables investors appeared first on Power Engineering International.

Heat Concept provides planning capabilities and actionable intelligence on how, where and what municipalities and utilities can do to decarbonize, and reduce reliance on foreign gas imports.

Heat generation in Germany accounts for approximately 40% of the country’s CO2 emissions. Renewable energy heating is therefore essential.

Join us at DISTRIBUTECH INTERNATIONAL, San Deigo, California

Understanding decarbonization involves analyzing data from multiple parties as well as sensor readings that need to be authenticated. Intertrust Platform securely manages distributed datasets, respecting regulations.

Heat Concept can analyze a municipality’s heating footprint for structures across a city, creating carbon baselines and analyzing future scenarios. Municipalities and their Distribution Service Operators and energy utility partners can use these results to plan their heating transition strategies and apply for funding from the German Federal government.

“Since heat transition is unique and dependent on each location’s specific conditions, these conditions must be transparent,” said Martin Möller, managing director of DigiKoo. “This transparency is made possible by Intertrust Platform and enables DigiKoo to provide community representatives, network operators, companies and households with a platform where they can exchange information and relevant information is available for all to see.”

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Heat Concept uses an E.ON developed AI platform that interfaces with Intertrust Platform to analyze a wide variety of data from numerous sources such as sensors on heating infrastructure, types of buildings, and socio-economic and demographic data.

Intertrust Platform ensures these datasets are accessed and managed efficiently and securely in accordance with German and European data regulations, and conditions set by the data rights holders. DigiKoo also plans to provide the analyses created by the Heat Concept to the public for community input.

“As Intertrust Platform’s use by major energy companies expands around the world, DigiKoo is an important partner in developing trusted data-driven applications for planning EV charging infrastructure, smart EV charging, and other important elements of the clean energy transition,” said Florian Kolb, Intertrust’s chief commercial officer and general manager, energy.

“Moving to a heating infrastructure based on clean energy is especially critical for Germany and other countries to meet their decarbonization goals and we’re proud to continue to support DigiKoo’s work in this field.”

The post A digital platform to aid Germany’s heat transition appeared first on Power Engineering International.

The tumultuous events impacting the energy sector over the past year have highlighted the benefits of nuclear technology, according to Crawforth. This has accelerated the development of progressive nuclear technologies, in turn, causing a new wave of nuclear deployment across Europe.

And this new wave is largely dominated by small modular reactors or SMRs.

Unlike large nuclear which is often plagued by cost overruns and delays, SMRs can deliver the energy transition affordably and reliably.

It’s one part of the global renaissance of different nuclear technologies, such as fusion and advanced modular reactors, on the generation horizon.

The post What are the nuclear technologies of the future? appeared first on Power Engineering International.

An increasing reliance on power, combined with the ongoing energy transition and current energy crisis, has resulted in increased demand for backup power generators.

As industry and society as a whole become more averse to the risks of power outages, the generator market is predicted to grow from around $13.53 billion in 2021 to $16.90 billion in 2027.

As demand for backup power increases, so does the need for load banks, an essential piece of testing kit that plays a crucial role in ensuring safe, reliable power across many industries.

What is a load bank? 

Wherever there is standby power, there is also a need for a load bank, a device used to create an electrical load that imitates the operational or ‘real’ load that a generator would use under operational conditions. 

A load bank can be used for a variety of applications, whether testing a diesel generator as a standby power supply, verifying the condition of a battery or UPS, or applying a full load to keep equipment running at its optimum efficiency.

In short, the load bank is used to test, support, or protect a critical backup power source and ensure that it is fit for purpose in the event that it is called upon. 

According to the International Energy Agency, global electricity demand grew by almost six per cent in 2021, driven by growing global populations, increasing digitalization, and a greater focus on sustainability.

The growth is showing no signs of abating, with McKinsey predicting that power consumption will triple by 2050 as electrification and living standards grow. 

As a result, organisations across all sectors are increasing their reliance on a secure, constant power supply to keep operations flowing as expected.

However, just as with any engine, maintenance is key to ensuring that generators will start when required – making it vital that anyone investing in a generator also explores the purchase or hire of a loadbank. 

Energy transition 

Efforts to address climate change are leading to increased electrification across industry, the transport network, and beyond.

This uptick in demand for power is coupled with the need to generate power from renewable sources – resulting in a rapidly-changing energy landscape.

The rollout of renewable power sources such as wind and solar brings with it ongoing investment in the power generation mix, as well as a renewed focus on how power systems are designed and operated. 

When harnessing natural sources of power, which are reliant on the wind blowing and the sun shining, managing a stable and constant supply can be challenging.

For this reason, there is an increased need for backup power options, grid balancing solutions, and better-connected grids.

This often involves the use of generators, which are used to increase or decrease generation, correct frequency deviations, and balance supply to demand.

Often a stopgap measure, generators are typically installed to run as standalone alternatives to the grid to provide an alternative power source during grid outages.

Yet, while their role as a reliable backup power source can keep consumers from being plunged into darkness, businesses from downtime, and hospitals from being unable to power vital equipment, generators are only a reliable source if properly maintained – and the only way to do that is to use a load bank. 

The energy crisis 

In the midst of the energy transition, Russia’s invasion of Ukraine has had far-reaching impacts on the global energy system, disrupting supply and demand patterns and impacting trading relationships.

As well as causing a prolonged shortage of power – most notably in Europe – the crisis has also seen energy prices rise, impacting households, industries, and entire economies. 

Where shortages threaten, governments may be forced to enact load-shedding strategies – a term used to describe the prioritisation of power allocation to hospitals and critical infrastructure.

For businesses, this prioritisation process may mean being without power for period of time – impacting productivity and profitability.

For this reason, many businesses are investing in backup power, ensuring that they can keep operating in emergency conditions if power cuts are implemented.

In France in particular, the government has been clear: businesses have been advised to make sure all emergency power generators are working, making load banks critical to meeting government recommendations. 

A digital-first society 

While the Digital Revolution has its roots in the 1960s and 70s, when technology started the transition from mechanical and analog to digital, the pandemic fundamentally shifted the way we live and work, necessitating a move to “digital first” almost overnight.

A McKinsey study estimates that during the first eight weeks of the pandemic, digital channel adoption fast-forwarded seven years.

Read the latest digitalization news

As well as forcing companies to accelerate their digital strategy and adoption, this transition also reset expectations for customers, who now expect companies to offer an array of digital services and interactions – with 100% uptime.  

To meet the challenges posed by an increasingly data-driven world, the data centre sector has experienced fast growth, with an anticipated 10.5% CAGR from 2021 to 2030.

In a sector governed by strict SLAs and expectations of continuous uptime, the issue of downtime continues to dominate the sector.

A report by the Uptime Institute at the end of 2022 identified that data centre outages were becoming increasingly costly, both in terms of downtime, reputational damage, and lost data.

Crucially, data from the UI showed that the biggest causes of power-related outages were uninterruptible power supply failures, followed by transfer switch (generator/grid) and generator failures – reinforcing that implementing a robust load bank testing regime is key to data centre uptime. 

Customer SLAs and zero-downtime 

Research from Zendesk suggests that 80% of customers say they’d switch to a competitor after more than one bad experience.

With customers demanding a fast and efficient service, regardless of industry, businesses can’t afford operational inefficiency.

In a world where zero-downtime is a critical part of business success, having access to reliable power supplies is non-negotiable, and will continue to entail the deployment of generators and load banks. 

The growth in demand for generators is a clear sign that businesses are reviewing their continuity and energy resilience plans.

Load banks are a critical part of that planning – with issues around grid reliability, energy shortfalls, and the transition to more sustainable power sources, it has never been more important that operators test their backup power systems.

By carrying out testing and maintenance, fuel, exhaust, cooling systems and alternator insulation resistance are effectively tested and system issues can be uncovered in a safe, controlled manner without the cost of major failure or unplanned downtime. 

Paul Brickman is Group Commercial Director at Crestchic Loadbanks.

The post <strong>The role of load banks in 2023</strong> appeared first on Power Engineering International.

However, as hydrogen is now becoming a mainstream avenue for decarbonisation of critical dispatchable power generation assets we must ensure that the relevant knowledge and best practices are transferred and adapted to the new conditions that will require additional engineering controls.

Such critical reviews and assurance around the safety aspect is a necessity as these avenues are increasingly being explored from resource planning to demonstrations in gas turbines. Among others the following properties influencing the safety approach should be considered:

• First, Hydrogen is a uniquely “leaky” gas due to its very small molecules. This characteristic manifests for precautions to minimise/eliminate non-welded joints and proper gas detection capabilities.
• Second, Hydrogen has a low lower flammability limit (LFL). This means that hydrogen can ignite easier than traditional fuels such as natural gas. In combined cycle applications for HRSGs, un-burned Hydrogen gas (from lean blowout, poor operability, startup, etc.) can accumulate, necessitating new procedures for HRSG ventilation and purge. It also necessitates purging of the fuel lines with inert gas before and after operation to prevent unintended fuel-air mixing in the lines.
• Thirdly, some materials become brittle when exposed to hydrogen, so identifying and selecting appropriate materials is essential.
• Finally, Hydrogen flames are mostly invisible (UV emissions only for premixed Hydrogen/air) requiring installation of appropriate leak and flame detection.

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All these properties and elements need to be considered in the design, to ensure safe hydrogen systems. These considerations can be most obvious for enclosed areas but that is not the only area for attention. The entire pathway for Hydrogen must be reviewed and safety procedures must be in place, including installation, charge/purge, usage, and reserve procedures.

The ETN Global hydrogen Working Group has reviewed current standards and safety aspects of hydrogen rich fuels in gas turbine enclosures.

The group has also started to develop a common approach built on the wide experience within the group and to develop a best practice safety standard on this topic. To do this as efficiently and as quickly as possible we need to ensure that the whole industry is moving forward on this in a coordinated manner.

The working group is therefore extending an invitation for participation in this project. If you have relevant experience and would like to contribute or have started a similar process, please contact ETN Global: info@etn.global

The post Highlighting safety standards for hydrogen in power generation appeared first on Power Engineering International.

Intermittency has long been the bane for grid operators seeking to bring more renewables online. The sun not shining and the wind not blowing has become the classic conundrum when explaining why our energy systems aren’t as clean as they possibly can be: non-renewable backup power is still key.

Energy storage, which can balance supply and demand, can come to the grid’s aid.

However, there isn’t nearly enough connected storage capacity to the grid to ensure a fully green and resilient system, says Thompson during an exclusive interview with Yusuf Latief during Enlit Europe 2022, explaining just how much storage is needed:

“The analysis we’ve looked at internally is that with some reasonable demand pattern changes, 250GWh would be suitable [in Europe and UK]. And without behavioural change and changes in usage patterns that could even go as high as a TWh…At the moment we have less than 2GWh capacity.”

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Whether policy, a lack of financing or the snails-pace red tape and permitting needed to get projects off the ground, barriers have been delaying deployment. “There’s probably 250GW of capacity [and] all types of energy projects, which are wanting to connect…the issue lies in how to connect.”

And to coordinate a turnaround of the situation, the approach that utilities take needs to switch. Thompson states how the very way clean energy projects are planned needs to change:

“The approach that the DNOs (Distribution Network Operators) and the TSOs (Transmission system Operators) need to take is to rip up the rule book on how they model technologies, start again and approach the system in a new way.

“[This needs to be done] in a way to fit as much capacity as possible onto our existing system. The next [step is figuring out] how to build a system that can accommodate all of this capacity.”

The post How much GWh storage capacity is needed for a resilient energy system? appeared first on Power Engineering International.

This project focuses on developing an innovative electric particle heater and pressurized fluidized-bed heat exchanger – a long-term thermal energy storage system that stores energy up to 100 hours, and other technologies to allow power producers to store solar or wind energy to generate continuous, reliable, grid-scale power. B&W’s proven and established pressurized fluidized-bed boiler technology is an ideal choice for advancing this technology to commercial operation.

To learn more about long-duration storage, John Meier, Director of ClimateBright Babcock & Wilcox, answers six questions.

Why is long-duration energy storage important?

JM: We need long-duration energy storage because renewables are becoming a larger part of the energy mix, and renewables like wind and solar aren’t available for power generation all the time. Energy storage is needed to bridge those gaps when the sun is not shining and the wind is not blowing to provide consumers a reliable and resilient electrical grid.

What is thermal energy storage?

JM: Thermal energy storage is the process of storing renewable energy in a high-temperature material, such as sand, ceramics, or molten salt. Sand is being used in the NREL DAYS long-duration energy storage project. Sand is an ideal abundant low-cost material since it is chemically stable over a large range of temperatures. The thermal energy in the sand can be later converted back into electricity or steam.

Our current design includes B&W’s pressurized fluidized-bed heat exchanger and will be able to generate up to 135 megawatts of power for up to 100 hours (four days) from stored clean thermal energy with zero CO₂ emissions. By facilitating long-term storage of zero-carbon, renewable energy, this technology enables power producers to deliver power to the grid 24-hours a day, including during periods of peak demand, or when solar or wind generation are not optimal.

Why is sand a beneficial energy storage medium?

JM: In terms of availability, sand is plentiful, inexpensive, and environmentally friendly. Sand is also a great energy storage medium. Think of walking across a sandy beach on a hot day. When you walk on your bare feet, you can really feel the heat of the energy stored in the sand. And the sand will hold that energy for a very long period of time.

How does the NREL DAYS technology work?

JM: A sand battery, as these energy storage systems are sometimes called, uses electricity to heat sand via heating elements. The heating elements are arranged in a formation that allows the sand to flow through, coming into contact with the elements and heating it up to 1200°C.

The heated sand is stored in an insulated silo. When we need to recovery the energy, the sand is moved from the silo into B&W’s pressurized fluidized bed heat exchanger. This is a direct contact heat exchanger that blows air up through the sand, causing it to behave like a fluid. The air passing through the sand absorbs the heat from the sand. The pressurized and hot air is then used to drive a gas turbine to generate electricity.

How long can the heated sand be stored for use?

JM: The sand can be stored and used for more than 100 hours. Since sand is inexpensive, adding more thermal storage capacity is incrementally inexpensive. Thermal energy systems such as these can provide 10s to 100s of megawatts of electrical power output.

Are there benefits to thermal energy storage vs. batteries such as lithium ion?

JM: The greatest benefit of thermal energy storage is duration. The current cutting-edge battery technologies such as lithium ion or zinc provide energy for 4 hours – if you want 8 hours, you need two of them at double the cost. Thermal energy storage can provide energy for power generation for hundreds of hours with only the incremental cost of sand to increase the duration of storage capacity.

About John Meier

John Meier is the Director of ClimateBright for Babcock & Wilcox, a leader in energy and environmental products and services for power and industrial markets worldwide. 

Starting with B&W in early 2022, Meier currently supports the commercial advancement of ClimateBright, B&W’s comprehensive suite of carbon capture, hydrogen and other decarbonization products and services designed to help utilities and industry aggressively combat greenhouse gas emissions and climate change while producing clean energy.

Meier has over 18 years of experience controlling emissions from coal-fired utilities and is a subject matter expert in the field of mercury emission reduction with several US patents and numerous publications in the field.  Currently, Meier is responsible for assisting clients throughout Europe and Asia Pacific in developing their decarbonization pathway whether through fuel switching, carbon capture technologies or production of low-carbon fuels with B&W technologies.  While originally from the United States, John currently lives and works in Berlin, Germany. 

John Meier will host “Long Duration Energy Storage: Opportunities and Challenges for Scale-up” at Enlit Europe on 30 November, 2022 at 2:30 p.m.

Join Enlit Europe in Frankfurt and be part of the conversation about the energy transition in Europe and beyond.

Register now

The post Six questions about long-duration energy storage appeared first on Power Engineering International.

You are invited to access the latest Europe Energy Talks – available online – which was hosted in Frankfurt, Germany, where experts discuss the challenges and opportunities of the energy transition in view of the expanding energy crisis in Europe.

Siemens Energy and Enlit Europe collaborated to host the Europe Energy Talks, where key players including BASF, EnBW, Shell, Uniper, and MVV participated.

Together, the panel explored how we can ensure energy security and affordability – and still accelerate the journey to net zero.

Moderator:
Kelvin Ross, Editor-in-Chief of Enlit Europe

Welcome address:
Ariel Porat, Senior Vice President, Head of Hub Europe, Siemens Energy

Panel:

Marcus Adlon, Managing Director | MVV Green Heat GmbH
Dr. Hannah König, Head of Procurement | EnBW
Dr. Holger Kreetz, COO Asset Management | Uniper
Jens Müller-Belau, Managing Director Energy Transition (Germany) | Shell
Christoph Schuette, Managing Director | Siemens Energy Germany

The energy transformation requires all of us to face some uncomfortable truths.
Join Siemens Energy to talk about them! 

The post On Demand: What is Europe’s role in the energy transition? – Europe Energy Talks appeared first on Power Engineering International.

Going back to the early 2000s, Endesa – Enel’s Spanish subsidiary – was very much a pioneer with smart metering in Spain, as the technology was at an early stage of development.

From the outset, Denda was involved in the initiative, which gained added impetus with Enel’s initial share acquisition of Endesa in 2009. The Italian giant had in fact pioneered in Italy the first country-wide smart meter deployment in Europe and among the first globally.

“I was working on looking at finding the right technologies for Spain,” recalls Denda, who with the successful completion of Endesa’s smart meter rollout based on Enel’s leading technology, became Enel’s global lead for smart metering solutions.

Subsequently, he took on responsibility for network technologies and innovation for the Enel Group’s global business line overseeing distribution – “everything related to the Operations Technology part of the grid” – until 2021 when the decision was made to bring together all the expertise developed in grid digitalization over the years, into a single entity named Gridspertise.

“Smart meters are a perfect example of how Enel’s role has been more industrial than simply as a user, including the design and engineering right up to the management of outsourced manufacturing,” he says.

“We felt that we should do this not just for Enel but for the whole sector. Worldwide, grid operators are facing the need to invest in the digitalization of power distribution infrastructures. We have the opportunity to share the technological expertise we have developed in Italy with countries that are tackling the energy transition, starting with regions where Enel Group is already present but with global growth ambitions.”

What is the Gridspertise offer?

With the digitization of grids, a priority shift is needing to be made. In September 2021, Gridspertise was officially launched and introduced as a technology and solution developer and provider, drawing on Enel’s over 20 years of experience in developments for diverse markets, from Italy to Europe, to Latin America.

While we have the strong foundation and backing of Enel’s credible technologies, we have introduced innovations, which in our opinion, are groundbreaking and could change the face of grid digitalization.

One is the QEd – Quantum Edge® device, which we expect to revolutionize how substations are digitalized. In addition, there are IT platform solutions that help optimize the flow of data, and other technologies such as digital twins.

We work with a huge ecosystem of partners and leverage the investment made by Enel in the past to find the best solutions for others. It is an acceleration of grid digitalization.

What is the approach to developing new technologies?

By looking at different markets, we collect their requirements and define their needs. We then challenge those needs with customers in different geographies.

We are fully conscious of the potential of our current product portfolio and we can determine the delta that needs to be developed to address specific needs. In those cases, Gridspertise continues to invest in innovation to reach the goal to satisfy those needs. In some instances, the Company launches co-creation activities working with customers and industry leaders.

We work with numerous customers, not only within the Enel Group. The company delivers its solutions based on a significant intellectual property portfolio of field-proven solutions to dozens of Distribution System Operators (DSOs) of different sizes in different geographies.

The question is: How do we create the right solution?

With a collaborative effort between Gridspertise and other market players, applying an open approach to design the right solution for each customer.

What is the QEd – Quantum Edge® device?

The ‘QEd’ is an innovative edge computing solution that we developed from scratch. It enables to virtualize key grid functionalities into applications and running them directly on the edge, increasing the reliability of the network and improving service quality for end users. This solution can do protections, RTUs for remote control, power quality measurements, routing, and distributed energy resources management – all technical functions that typically would need different individual devices.

Once intelligence is put into the grid, and close to the transformer, many use cases are opened up; flexibility management, power flow optimization, fault detection, predictive maintenance, etc. With the capabilities of artificial intelligence, the functions that typically would be done in the cloud, or on a central system, can be extended to the edge. This brings it closer to the problem of reduced latency.

We have already made the first deployments within Enel and started the first co-creation programs with customers in order to fine-tune their use cases. In 2023, we will start to see deployment happening on many different sites.

The QEd Co-creation Program is also available for technology providers to build applications that run on that hardware.

What other developments are in the pipeline?

We are focusing our efforts on the digital platform.

For example, we have developed Digital Asset and Vegetation Intelligence, which is very helpful for predictive maintenance. Simple use cases, such as the identification of vegetation in critical closeness to the overhead lines, can be automatically optimized, creating value by reducing operational costs for trimming. Moreover, the solution enables automatic recognition of anomalies on specific grid components, preventing the risk of failure.

In terms of technology, the platform enables advanced functionalities to customers or even operates the technology as a service.

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What gaps are there in the market?

Every geography presents specific needs and gaps to be covered.

In APAC, for example, the main issues are power losses and grid quality, whereas, in the US and Europe, where the digitalization level is more advanced, there is a need to integrate flexibility dynamically. Then there are some areas where the quality of the supply is still a big issue in regular situations or some emergencies.

In terms of solutions, our portfolio is able to cover the entire value chain of DSOs’ operations and we are progressively including new solutions focused on addressing the future needs of grid operators all over the world.

Much of the focus we see, will be on the integration of electric vehicles, storage, and the demand side in real-time at the control level.

What’s next for digital solutions and services?

The utility sector has been a very traditional one but over the past five to ten years there has been a shift to the cloud and away from legacy technologies, and that mindset has become a reality. The next step we will see is ‘everything as a service’. It will bring a lot of value as there are many power grid operators which do not have the technological muscle to make the jump.

In the near future, DSOs will also need help in reducing their carbon footprint and achieving net zero emissions. Sustainable Grids are not only determined by their ability to host more renewable energy sources. They require more sustainable operations and the adoption of zero or low–emissions equipment, materials, and digital technologies. To reduce the grids environmental footprint, Gridspertise strives to deliver integrated solutions that are sustainable by design.

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Gridspertise’s advanced digital solutions for a smart and resilient grid

How would you evaluate the past decade and what do you see for the future one?

In the last decade, smart meters have helped stabilize the grid with granular information on consumption, allowing for real-time monitoring of electricity use, advanced management of the technical parameters of the grid, and detection in near real-time critical events, such as blackouts. The increasing awareness of low-voltage grid information has also enabled the improvement of the management of the medium-voltage grid.

Coming up in this decade, I see three evolutions. The first one is the transformation of the traditional grid into a smart grid. This means that the grid will need to increase its hosting capacity, work on network flexibility, and make system operators more responsible. In the future, I think we will have grids that can automatically reconfigure in real-time according to the situation.

The second trend I foresee is related to the shift towards electrification and the consequent increase in power consumption. This together with an increasing demand for information in real-time will stimulate customer engagement and participation in the electricity sector as well.

The third aspect is that the digitalization of the grids requires the right training and skillsets for managers and the workforce, as well as the right digital tools to streamline field operations. While the lack of grid managers with expertise in digital grids represents a huge challenge, the development of digital tools and their integration with operations is already in progress. Our solutions, for example, augmented and virtual reality, can be coupled with a digital twin overlay for workers in the field.

What is the vision for the future grid?

In the short term, the top priority is to accelerate grid digitalization to manage the key challenges of grid operators: loss reduction, quality improvement, reliability, etc.

In the future, with the increasing electrification and distributed generation, the grid will still play a central role to manage the complexities of the market. Even if everyone becomes a generator, there will still be a need to share and trade excesses. The electricity grid is like the internet of power and it will be extended even in the most remote locations.

For power grid operators, their role will also be different: by 2050 they will also be digital operators with the digital control of energy – unless we find another energy source even better than electricity, but that’s not foreseeable in my mind!

** The recent announcement by Enel of an agreement to sell 50% of Gridspertise to CVC Capital Partners is a further sign that the smart grid space is vibrant and at the center of the transformation of the current energy model, making this conversation even more relevant.

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About Robert Denda

Robert Denda is the Sole Administrator and CEO of Gridspertise. Previously, he served as Head of Innovation & Industrialization and Head of Network Technology and Innovation at Enel Grids. In that capacity, he led the development and application of digital grid technologies at Enel, the largest privately-owned international operator of power distribution grids, serving 74 million customers.

As Global Head of Smart Metering Solutions from 2014 to 2015, he oversaw Enel’s international rollout of digital meters, building on his previous experience in coordinating the rollout of 13 million smart meters for Enel Group subsidiary Endesa in Spain. At Endesa, Dr. Denda also served as director of the R&D department, innovation manager in the telecommunications sector, and manager of technology services at Endesa Ingenieria. As well, he is an active participant in European and international energy sector associations.

He holds a degree in Computer Science and Business Administration and a Ph.D. from the University of Mannheim in Germany.

Robert Denda will be a Keynote speaker at Enlit Europe on 29 November 2022; addressing ‘Europe’s Balancing Act: Energy Security and the Green Transition’. View more details on the Keynote here, and register to attend the event below.

Join Enlit Europe in Frankfurt and be part of the conversation about the energy transition in Europe and beyond.

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The post A smart grid journey with Robert Denda, Gridspertise appeared first on Power Engineering International.

This was the standout highlight from the latest report on the European energy market from data analyst EnAppSys.

The record gas prices were driven primarily by continuing conflict in Ukraine and the changes in the gas flows through Nord Stream 1.

Firstly, Russia shut down the pipeline’s gas flows to Germany for maintenance in July for ten days. Following the conclusion of the maintenance, gas flows through the pipeline were reduced to just 20% of capacity in August and by September flows were halted indefinitely.

Towards the end of September, gas leaks were observed at both Nord Stream 1 and the as-yet unused Nord Stream 2, meaning that the pipelines are likely to remain out of use for an extended period.

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These events saw gas prices in Q3 climb from the €145.48/MWh seen at the close of Q2 to reach a peak of €308.18/MWh by the end of August. By the end of the quarter, however, gas prices fell back to €159.40/MWh as gas storage facilities were filled with reserves.

Soaring gas prices saw some countries, including Germany, Spain and the Netherlands, favour coal-fired generation rather than gas during the quarter.

High temperatures in the first half of the quarter caused further issues in the French nuclear fleet, further squeezing European energy supply and ensuring that France remained a net importer of energy.

Meanwhile, a drought in Norway reduced hydro generation in this country and reversed the flow of its interconnectors from a net export to a net import position for extended periods.

Jean-Paul Harreman, director of EnAppSys BV, said: “As with the previous two quarters, Q3 2022 was impacted by the war in Ukraine and the unfavourable climate conditions that affected hydro and nuclear energy generation in Europe.

“Since Russia began the invasion of Ukraine in March, gas supplies to Europe have been reduced significantly and, as of early September, supplies to Nord Stream 1 pipeline were completely stopped.

“With the explosions at both Nord Stream 1 and 2 later in the month, it’s clear that there will be no flows through the pipelines any time soon.

“The pressure from all of these factors has resulted in increased gas prices across the continent. Due to the soaring gas prices in the EU as well as a multitude of other factors such as the EU’s higher dependency on Russian oil, wholesale electricity prices relative to prices in the GB market have become even higher for many EU nations.”

The third quarter saw the lowest hydro and nuclear output of any Q3 in the last five years with 89.9TWh of hydro and 145.7TWh of nuclear generated across the continent.

Renewables saw an 11% increase compared to Q3 2021 and fossil fuel generation was 6% higher than in Q3 2021, reversing a decline seen in recent years.

French nuclear was the biggest contributor to Europe’s fuel mix in Q3 2022, producing 22.3% of the total. Gas was the next largest contributor with 21.5%, followed by coal/lignite (17.9%), hydro (13.8%), wind (11.0%) and solar (8.9%). Biomass (3.5%), waste (0.6%), oil (0.3%) and peat (0.1%) made up the rest of the total.

Join Enlit Europe in Frankfurt and be part of the conversation about the energy transition in Europe and beyond.

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Great Britain boosts gas production

Britain produced its highest third quarter levels of gas-fired generation since 2011, despite soaring gas prices which pushed up electricity bills for businesses and households.

The 31 TWh of gas-fired output produced during the quarter helped to meet high demand for exports from GB to Europe through interconnectors with France, Norway, Belgium and the Netherlands. This was a consequence of problems with the French nuclear fleet, a Europe-wide drought and higher gas prices on the European mainland.

Britain continued to be a net power exporter again this quarter, having become a net exporter for the first time in the previous quarter. Total net power exports from the GB interconnectors in Q3 stood at 4.59TWh, a 26% increase from the previous quarter.

Paul Verrill, director of EnAppSys, said: “This quarter saw increased pressure in the GB electricity market as gas prices resumed their escalation, having fallen in the first half of the year following the initial spike in prices at the outbreak of the war in Ukraine. The consequent increase in generation costs during Q3 led to a rise in wholesale power prices, with all-time high averages for day-ahead, within-day and system prices.

“Nevertheless, gas prices and electricity generation costs were generally more favourable in GB than in mainland Europe, so GB remained a net exporter this quarter. This was primarily due to GB’s lower dependency on Russian gas imports than other European countries. Most of GB’s gas is produced in the North Sea, while imports come mainly from Norway. LNG imports come from Qatar and the US, meaning that very little GB gas has historically come from Russia. This means that GB has been more shielded from the worst of the recent gas spikes than many of its European neighbours which do not have LNG import facilities.”

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