The energy conservation measures include the installation of LED lighting, boiler plant and heating system upgrades, converting fuel sources from natural gas to electric heat pump systems, upgrading electrical distribution systems and installing a geothermal ground source heat pump system.

In addition, the project will replace natural gas clothes dryers with ventless heat pump dryers, install water conservation measures and upgrade building envelopes to be more energy efficient.

According to Ameresco, the energy upgrades are designed to save over $2 million in energy costs per year and reduce greenhouse gas emissions by more than 27%.

In addition to the environmental benefits, the project is expected to create 125 new jobs in the Edmonton area over the next two years.

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Ameresco undertook a comprehensive project evaluation in 2022, which included the completion of audits, the development of energy-saving measures and a subsequent feasibility study.

This multi-phased project is currently in the design stage, which is anticipated to extend through the remainder of the year and into early 2025.

To initiate project implementation, fast-tracked measures will involve the simultaneous replacement of 10 boilers across 5 buildings and initiating LED lighting upgrades in 110 buildings this summer.

With multiple initiatives underway, the project’s full completion is expected by the end of 2026.

“CFB Edmonton houses some of the most prestigious and experienced units in the Canadian armed forces,” said Bob McCullough, president of Ameresco Canada.

“The enhancements to the lighting, heating, cooling and water systems will provide troops with a more modern, comfortable and efficient energy system while greatly benefiting the surrounding community through their lowering of carbon emissions.”

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

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

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

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

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

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Programme details

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

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

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

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

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

The programme needs the approval of the CPUC and FERC.  

Citizens investments

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

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

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

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

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

Originally published on Power Grid.

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

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

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

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

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

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

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

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.

Farrand expands on how Trilliant is supporting global utilities with their smart grid networks for a new energy future.

Watch the full video interview with Gavin Farrand below.

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

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

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

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

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

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

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

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

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

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

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

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

Modernising the energy grid is a complex, large-scale endeavour, ranging from distributed energy resource management to grid digitisation, smart metering to the rise of prosumers, and much more.

Grid modernisation

In the coming decades, energy needs are forecast to increase as the global population continues to rise and as countries develop and their economies grow. During this transformation, accelerating the availability of clean, renewable energy is critical to meet this growing demand while addressing climate concerns.

As the world looks to a net zero future, technological advancements in electrification are helping address challenges associated with scaling renewables and enabling them to become viable alternatives to traditional fossil fuel sources of energy.

Furthermore, as the grid evolves, the distribution, storage and management of electrical energy are changing. There is a shift from centralised power stations to distributed renewable energy- characterised by smaller and widely spread power generators, usually coupled with energy storage capacity, which feed into the distribution grid. Decentralisation results in bidirectional energy flows, where end consumers become prosumers, necessitating the evolution of new energy markets. Done right, decentralisation can promote energy resilience and reduce transmission losses.

From a technology perspective, this distributed nature of energy assets like cars, homes, and manufacturing sites is giving rise to the Intelligent Edge where analogue sensing meets digitalisation. Simply put, we need intelligence at all the critical nodes: across every energy consumption, production, distribution, and reserve modality.

Watch the full video interview with Patrick Morgan below.

Data is the lifeblood of this new technology world. To create and capture value, technology developers like ADI must interact in new ways throughout the ecosystem. Our focus is to learn and co-create, as we develop complete subsystems at the Intelligent Edge with our partners. As we grow, we are bringing in new expertise, in areas that stretch beyond the typical approaches into areas like artificial intelligence, data science, virtualisation, battery chemistry, and more. Plus, we are advancing our IP strategy to include systems and standardisation to drive the industry. In taking a holistic view of Intelligence at the Edge and in designing with the total cost of ownership in mind, we are enabling the Intelligent Edge to stretch into the key area for value creation and growth.

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There is no time to waste and with the signs of climate change all around us, a combination of innovative technology and legislation is helping us to electrify and ensure a brighter and healthier future for us all. At ADI, we look forward to engaging with the full electrification ecosystem to help realise its decarbonisation potential.

Regardless of complexities, ADI solutions aim to simplify the paradigm into Energy Conversion, Energy Management, and Energy Storage. It is our unique position in the ecosystem, across the industrial, energy, automotive and consumer markets, which provides us with a macro-to-micro perspective into the challenges and opportunities.  

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

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

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

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

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

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

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

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

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

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

Digital adaptation

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

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

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

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

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

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

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

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

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

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

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

Electrification and the EV era

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

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

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

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

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

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

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

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

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Renewable integration and non-traditional players

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

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

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

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

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

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

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

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

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

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

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

Let me know.

Cheers,
Yusuf Latief
Content Producer
Smart Energy International

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ChatGrid, the brainchild of Pacific Northwest National Laboratory (PNNL) optimisation and grid modelling researcher Shrirang Abhyankar, was conceived to exploit the question-and-answer approach of generative AI tools to support grid operators in their decision making.

With this, the user can then ask a question such as: “What is the generation capacity of the top five wind power generators in the Western Interconnection?” with the response of a visualisation showing the desired information.

Users can ask questions about generation capacity, voltage, power flow and more, while customising the visualization to show different information layers.

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Abhyankar says the aim is to simplify the experience for grid operators who have to make many decisions as they monitor the grid in real-time.

“We’re envisioning a new way to look at data through questions. ChatGrid allows someone to query the data – in a literal sense – and get an instantaneous answer.”

ChatGrid runs on a publicly available large language model, with the input data the synthesised data from the Exascale Grid Optimisation (ExaGO) model, which was developed to take advantage of the power of supercomputing to simulate the nation’s power grid in real time.

Moreover, to further protect grid security, the model was not trained on the data itself.

Instead, the data was compiled in an internal database in columns with headings such as ‘capacity’ and ‘location’ of power plants and the model used to produce a ‘structured query language’ (SQL) that allows ChatGrid to search this database for its answers.

Work in progress

For Abhyankar, ChatGrid remains very much a work in progress.

He hopes that once grid operators start using ChatGrid and providing feedback, a better version can be built that they can then safely use in their control rooms with real-life data.

For that to work, ExaGO’s developers need the data to be useful on regular computers as well, however.

Further, while ChatGrid is available for download on GitHub, the process takes a few steps and once the feedback starts rolling in, the development of a one-step download process is anticipated.

Users also are invited to play around with the phrasing prompts and questions to assess how to produce the best answers.

The Business Demand Response programme, which aims to ensure grid stability and reliability, will see eligible PSE business electric customers earn payments for making targeted energy reductions during periods of peak demand or grid emergencies.

Each participant’s earnings will be a combination of its committed load reduction capacity and the average of its participation across all events within a given season, multiplied by a fixed amount per kilowatt.

“Partnering with Enel is a great opportunity for us to continue our journey to grow our demand response programmes, providing ways to create value with and for our commercial and industrial customers,” said Aaron August, senior vice president, chief customer and transformation officer at PSE in a release.

“Together, we can unlock the potential of energy optimisation, utilising smart technologies in support of a clean energy future.”

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Under the terms of the agreement, Enel will work with PSE to recruit commercial and industrial customers from within the utility’s electric service area; PSE serves approximately 1.1 million electric customers in 10 counties, namely in Western Washington.

Enel will also help Washington customers enrol in the programmes, develop customised curtailment plans that demonstrate how customers can make targeted energy reductions during demand response events and manage a portfolio of demand response resources on behalf of customers.

“As the power grid evolves and extreme weather is on the rise, we shouldn’t have to choose between sustainability and reliability,” said Molly Jerrard, head of demand response at Enel North America.

“Demand response helps Washington integrate more renewables onto the grid while minimising disruptive events. And through incentive payments, large energy users are rewarded for playing their part. We’re glad to support PSE in maintaining a modern, flexible and cost-effective grid through demand response.”

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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Pacific Gas & Electric (PG&E), the largest utility in California, is partnering up with energy software business Kaluza and EV charging company Wallbox to pilot the smart charging and Vehicle to Everything (V2X) technology.

Through $1.5 million in phase one funding from the California Energy Commission (CEC) REDWDS grant, the partners will develop new technologies to incorporate dynamic price signals for both one-way ‘V1G’ and bidirectional ‘V2X’ charging.

The project will allow drivers to ‘set and forget’ their EV charging: using Kaluza’s algorithms, a smart EV charger, driver preferences, live grid data and dynamic pricing structures, vehicles will charge optimally to reduce grid pressures during public safety power shutoff events.

The programme will comprise 330 vehicles, with a commitment to deploy at least 50% of these assets in low-income communities.

Some of these assets will be connected to Wallbox’s bidirectional charger, Quasar 2, enabling users to charge their EVs and export power back to their homes or offer emergency back-up power when the grid is down. EVs store around 70kWh in their battery – sufficient to power an average home for three days, longer than most stationary batteries.

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Project progression

If the project is successful, additional CEC funding of up to $4 million will be made available through a second phase to continue deploying managed charging and bidirectional solutions in California.

Mike Delaney, vice president of Utility Partnerships and Innovation at PG&E, commented on the V2X partnership in a release: “Our work to prepare the grid to power and support millions more EVs over the next decade includes creating the most robust vehicle-grid-integration portfolio in the world.

“To that end, we are collaborating with the best and the brightest to integrate new bidirectional charging capabilities and to provide the platform, expertise, and cross-industry leadership to enable our customers with a range of options that unleash the full potential of their EVs.”

Phase 1 of the three-year pilot kicks off this year, with customer enrolment expected at the end of 2024. The programme operation and data collection will extend through September 2026.

PG&E provides natural gas and electric services to approximately 16 million customer, with 600,000 operating EVs throughout the utility’s Northern and Central California service area.

In a release, the partners cite high initial costs and the reliance of low-income individuals on their vehicles for work, posing challenges for these communities in transitioning to EVs. The project partners will further collaborate to lower the upfront costs of switching to an EV and showcase the efficiency of managed charging programmes in ensuring affordable charging and constant vehicle readiness for customers.

Additional partners in the initiative include community-owned electricity provider Sonoma Clean Power and Valley Clean Air Now (CAN). The former aims to make EV charging more accessible for low-income communities and the will support customers in learning about options to make use of second hand EVs.

Jonathan Levy, US managing director at Kaluza, commented: “We are thrilled to be selected for up to $6.2 million in funding from the California Energy Commission, enabling Kaluza to accelerate our work in the United States.

“With California rapidly approaching 2 million cumulative EV sales, managed charging with software solutions like Kaluza means everyone’s a winner – including EV drivers, utilities like PG&E, the grid and the planet.”

The scientists developed a model that simulates storm damages to the Texas power grid and studied 10,000 realisations of potential damages for each of seven historical tropical cyclones, including the major hurricanes Harvey (2017) and Ike (2008). Their approach allowed them to reproduce observed supply failures.

The Texas electric power system was chosen due to its high frequency of exposure to hurricanes and weaker tropical storms, providing the perfect context to study these complex effects and potential resilience adaptation options in depth.

The researchers, who published their findings in Increasing the resilience of the Texas power grid against extreme storms by hardening critical lines, find that large-scale power outages caused by tropical cyclones can be prevented almost entirely if small but critical sets of power lines are protected against storm damages.

Study author and PIK scientist Christian Otto commented in a release on their analysis: “We found that the failures of certain lines can trigger large-scale outages affecting whole regions or cities. Regions or cities fail in one major cascade, rather than gradually.

“Our research shows that such cascades can be avoided almost entirely if less than 1% of the overall grid – this is 20 lines in the case of the Texas power grid – is protected against storm damages, for example by reinforcing transmission towers or using underground cables. This way, the risk of outages in major population centres can be significantly reduced. Notably, protecting the same small set of relevant lines works for all seven historical hurricanes considered.”

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Modelling grid to storms

Based on a model of the Texas power grid, the scientists coupled a model of the evolution of tropical clones’ wind fields with a dynamic model of the Texas power grid in a spatio-temporal approach, allowing it to describe the evolution of storm-induced cascading power outages.

“For the first time, our analysis shows how an electric network reacts to evolving storms. By simulating the co-evolution of wind-induced failures of high-voltage transmission lines and the resulting cascading power outages, we discovered which parts of the electricity network are most critical as their failures have cascading impacts leading to major power outages,” said PIK scientist and study author Frank Hellmann.

“This appears to be a property of the network itself, rather than the storm’s precise path.”

“This is a challenging task, as the time scales at which storms and power outages evolve can be very different,” added scientist Mehrnaz Anvari, who conducted the research at PIK and is now group leader of Network Evaluation Technologies at the Fraunhofer Institute for Algorithms and Scientific Computing.

“By combining PIK expertise on the event-based modelling of tropical storms and power grids, we managed to identify the critical lines, whose failure can trigger large blackouts.”

“Tropical cyclones are one of the most destructive category of extreme weather events,” said Katja Frieler, scientist and head of the Research Department, Transformation Pathways, at PIK.

“As peak wind speeds of the most intense storms are projected to increase with global warming, the damage caused by these storms is likely to increase unless we adapt accordingly. Our new method gives grid operators a crucial tool to identify effective adaptation options and can help make our infrastructure networks fit for a new climate reality.”

Announced during DISTRIBUTECH International 2024, hosted in Orlando, Florida, the Cooperative won the prize for recognition of their journey to becoming a more inclusive, equitable workplace.

REC was formed in 1980 after the consolidation of two cooperatives, Virginia Electric Cooperative in Bowling Green and Northern Piedmont Electric Cooperative in Culpeper.

The award, which highlights an electric utility who has best demonstrated achievements in the areas of diversity, equity and inclusion (DEI) in the workplace, saw REC take the win home.

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Achievements of REC cited during the awards presentation includes their work with the Center for Energy Workforce Development (CEWD) by participating in the development of their DE&I roadmap.

The Cooperative has also received certification through Virginia Values Veterans (V3), a Virginia Department of Veterans services program, created to educate and train employers on how to connect with personnel assets to maximise the productivity of the workforce.

Speaking on the behalf of REC and receiving the award was Peter Muhoro, REC’s Chief Strategy Technology and Innovation Officer, who has been with the company since 2020, discussing how any plan for diversity within the workforce has to start from the top.

“DEI is about our core values. Not only at the executive level, but also for the Board of Directors … because if you have a plan from the top, no matter what barriers (you go up against), you will have a plan.”

During the presentation, REC was also recognised for their accessibility functions, including a website which is accessible for visually and hearing-impaired users.

DE&I for leadership

Muhoro also cited insight from REC’s President and CEO Dr John Hewa, who commented, “At REC, diversity means difference.

“Every person here brings unique experiences that, when combined, contribute to REC as a team being positioned as the leaders that we are in the electric utility industry.”

Giving his advice to leaders in the electric sector, Muhoro cited three key pieces of advice:

“Surround yourself with people who light up when you walk in, because this is how one knows they’re doing something right.

“Second; slow is the fastest way to get somewhere – don’t rush. Some of us want to rush in but this does not get done overnight.

“Lastly, the top of every mountain is the bottom of the next – keep climbing.”

Originally published on power-grid.com

Other top initiatives are renewable energy integration, grid modernisation and microgrids and disaster response and recovery plans.

Furthermore, the utilities are adopting new approaches to improve outage recovery times through advanced networking, with predictive maintenance analytics topping the list, followed by smart grid technologies and enhanced communications, as well as the use of drones and robotics to inspect assets.

Phil Beecher, President and CEO of the Wi-SUN Alliance, comments that extreme weather events are fast evolving from a rare occurrence to something that should be built into the risk profile of any utility company.

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“The emergence of smart grids, microgrids and other technologies, like predictive maintenance and fault finding, offers a way of controlling costs while increasing resilience and stability to help mitigate the impact of outages.”

But, he adds, “technologies like this are only as good as the underlying communications network to provide reliable and secure delivery of the data needed to deliver a truly smart grid.”

The research was conducted among more than 250 senior professionals in the US utilities and power sectors and highlights the role of new tools and technologies to help improve resilience and outage recovery times as weather events and environmental disasters become commonplace.

According to US Department of Energy data cited by the Wi-SUN Alliance, extreme weather conditions – from heatwaves to Arctic vortexes – have doubled power outages in the US over the past 20 years.

The research also founds that utilities recognise opportunities to integrate artificial intelligence technologies to address resilience, with viable use cases including energy consumption forecasting, automated fault detection and grid optimisation.

Looking ahead to the next five years building infrastructure resilience remains among the top issues, with others including security enhancement, customer-centric services, renewable energy integration and IoT integration and data analytics.

The study was conducted for the Wi-SUN Alliance by Censuswide in February 2024.

The inertia measurement technology, GridMetrix, offers network operators continuous measurement and analytics data, including real-time measurement of inertia.

The collaboration, supported by the New York Independent System Operator (NYISO) and utilities across the state, will be showcased in a demonstration project to confirm the operational and grid planning benefits.

New York’s Climate Leadership and Community Protection Act mandates the quadrupling of offshore wind capacity to 9,000MW by 2035, doubling distributed solar deployment to 6,000MW by 2025, and deploying 3,000MW of energy storage by 2030.

“We are delighted to see NYSERDA and the New York State utilities exemplify climate leadership by supporting and adopting our technology,” said Marc Borrett, CEO of Reactive Technologies. “This award underscores New York’s dedication to fostering new technologies that advance a future powered by clean energy. We are eager to continue our collaboration with utilities across New York State, aiding them in achieving their net zero goals, safer and faster.”

Reactive’s GridMetrix technology has been deployed globally, serving utilities in Asia, Europe, and the Middle East.

“NYSERDA is moving forward strategically to support the demonstration of tools like Reactive Technologies GridMetrix through our Future Grid Challenge program,” said Doreen M. Harris, president and CEO, NYSERDA. “Investments in innovation are investments in a grid of the future that incorporates clean energy and allows for dynamic management and operation to ensure resilient and reliable transmission and distribution, even when factoring in the impacts of climate change.”

The Future Grid Challenge is part of NYSERDA’s Grid Modernization Program included in the State’s Clean Energy Fund (CEF), which is providing a total of $140 million through 2026 to further research, develop, and provide funding for solutions that support the advancement of a smart, modernised electric grid.

Originally published on power-grid.com

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.

According to Hoffman, speaking at DISTRIBUTECH International, extreme weather events have brought to the fore an urgency for utilities to look at new ways of partnering on advanced analytics.

“A message that I want to get across to folks here at the forum is that we have an opportunity, we have a critical mandate and critical urgency,” she added, stating the need for power sector players to be responsible and plan for these events, that are no longer a ‘once-every-other-year’ occurrence.

Hoffman referenced bouts of funding made available by the US DOE’s Grid Resilience and Innovation Partnership (GRIP) programme.

The major funding programme, part of the Bipartisan Infrastructure Law and consisting of $10.5 billion, aims to enhance grid flexibility. Additionally, as emphasised by Hoffman, it recognises the need for a resilient power system to combat the growing threats of extreme weather and climate change.

Indeed, weather-induced outages are becoming ever more frequent; a common news headline calling for utilities to overhaul their grid planning. According to Hoffman, new collaborations will be crucial.

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“[This planning] requires a lot of collaboration. It requires building things at scale, looking at data at scale, looking at partnering so that we can do the analytics at scale.”

Referencing wildfires on the US west coast that called for public safety power shut-offs, Hoffman stated how the opportunity to mitigate the impacts of these events lies in the collection of multiple data streams.

“To better understand and predict the potential for wildfires, there’s a lot of data streams out there: LIDAR data; forest service data; fuel loadings; drought conditions; temperatures; heat zones.”

Hoffman explained how accounting for all of these data streams, pulling them together with transmission planning and mapping, will open new avenues for mitigation and prevention of their impact on the grid.

Considering key questions, she added, such as power safety shut off being coordinated in larger or narrower areas or how to pre-position or lighten the load in the system due to event conditions, would then work towards minimising the damage and effect on our power systems.

“That’s one example, to merge data streams, sensor information, and be able to capitalise on that as an industry and be able to provide feedback to the customer.

“That’s what it goes back to … this call from the customer for greater transparency, greater awareness, an expectation by the customer for us to do more to provide them more information.”

Kass is an AI futurist and former head of Go-To-Market at Open AI. He navigates the challenges and opportunities that lie at the forefront of AI innovation. He dissects the paradoxical landscape where technology moves at an astounding pace, yet practical, scalable solutions remain elusive.

Whether or not you agree with his thought-provoking projections for the future of AI, it is clear this technology has massive implications for not just our lives but the energy industry as a whole. Personal concerns and issues aside, the potential contributions of AI to our work lives are … close to limitless, it seems.

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Discussing the upcoming “most profound industrial revolution in human history,” driven by AI, Kass said the future is moving toward us at an incredible clip. The movement is now toward developing AGI, or artificial general intelligence.

In essence, at some point, AI will become smart enough that it will help itself generate scientific developments. Over the past few years, scientists have gone from building systems that think in straight lines to building systems that think like your brain, in parallel. Kass said we will achieve AGI by 2030, maybe earlier.

So, is AI going to take our jobs? Kass said this is a concern he hears often when he talks to organizations. Short answer, no. In fact, we as humans are going to harness this technology to improve our experiences, not the other way around. AI will make us more human, not less, he said. AI does not have vision, wisdom, courage, curiosity, empathy. These are qualities that define us as humans.

What AI can do is improve our work lives and processes, boosting worker productivity and job satisfaction. If AI can handle the 50% of their job that many people don’t actually enjoy, we can find more time in our day to do the parts of the job that we love, that require that human input. AI can gift us an “abundance of time,” Kass said, allowing us to rediscover what it means to be human.

What are the challenges and hurdles facing AI? Besides scepticism and resistance to adopting this technology, the industry is hampered by three issues: A computing deficit (lack of microchips), an energy deficit, and bad policy.

DISTRIBUTECH is a perfect place to talk about that second challenge.

Kass said the amount of energy required for AI is equivalent to solar fields the size of Arizona and Texas. And related is the lack of ability to store and transmit the energy needed, to these computers. In a bit of a “the chicken or the egg” scenario, Kass said, “AI probably begets fusion or nuclear but fusion or nuclear probably begets AI.”

Kass encouraged attendees to use the technology and to think about how it can improve their processes and ultimately help build the grid of the future.

Other keynote speakers Tuesday morning included Tom Dietrich, president and chief executive officer of Itron; Harry Sideris, executive vice president – customer experience, solutions & services with Duke Energy; Ali Ipkachi, PhD, chief visionary officer with OATI; and Orange County Mayor Jerry Demings. Duke Energy is the DISTRIBUTECH International host utility, and Itron and OATI are both sponsors.

Dietrich started by talking about big-picture challenges for the industry: infrastructure, environmental, and societal. He discussed the case for enabling grid edge intelligence and said the future is how we make use of all the data that is available to us. Foreshadowing what Kass would discuss later, he pointed out that CapGemini recently reported only about a third of utilities are doing something with generative AI, which can aid in dealing with many different “problems” in the industry.

Sideris discussed the utility perspective on the future, saying Duke Energy has more than 50 GW of generating capacity but plans to double that because of growth in electric demand in its service territories. The utility has 8.3 million electric customers in six states, and examples of this significant increase in demand include a 1,000 MW data centre for AI (sense a theme?) and 500 MW chip manufacturing facilities coming back to the U.S. from overseas.

Electrification is growing rapidly, with companies converting from gas to electric boilers and converting their HVAC systems from gas to heat pumps. And that doesn’t include the electric vehicle space, with about 120,000 now but expectations of over 1 million by 2030.

Duke Energy is on a journey to net zero by 2050, which includes getting out of coal by 2035 and adding “a lot more” renewables, more gas to maintain reliability, and eventually more nuclear, which Sideris said is “the key to the future.” On the grid side, he said the company will spend $73 billion in the next five years, half of that on the grid, to be ready for this electrification and the two-way power flow from customer generation resources.

Sideris also said the utility avoided 1.5 million customer outages from smart technology and self-healing networks. He concluded by saying technology will be critical to what the utility needs to do in the future, so they must embrace it and look at how they can scale it faster.

Ipkachi discussed the “turning point” of the industry as the generation mix is embracing renewables and cleaner energy and the boundaries between transmission and distribution are fading. In 2023, the generation resource addition was 54GW, 84% of that being renewables and storage. At the same time, the interconnection queue stands at 1.9TW, 94% of that being renewables and storage. He said virtual power plants are the most cost-effective resources when compared with alternative generation and DERMs are an essential and enabling component of this architecture.

And Demings discussed the county’s efforts toward resiliency and sustainability. Orange County has many initiatives, including an Orange County Utilities Department floating solar array, a Smart Cities partnership launching its first platform this April, the new Orange County Innovation Lab that will harness the power of AI, a partnership with Duke Energy to install DC fast charging stations for EVs and more. In addition, the Orange County Convention Center rooftop solar installation will be expanded to a capacity of 2 MW.

Originally published by Elizabeth Ingram on power-grid.com

Graphene is often described as the ‘wonder material’ and it has a name for it but that is for applications such as energy storage.

But another candidate for the moniker is the less high-tech sounding perovskite that is expected to bring the next step change for solar photovoltaics, with new levels of efficiency and cost-effectiveness.

Perovskite, which is named after the Russian mineralogist Lev Perovski following its discovery in Russia’s Ural Mountains in 1839, is a naturally occurring mineral of calcium titanium oxide (CaTiO3).

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Despite being so long known it is only in this century that perovskites, i.e. not only perovskite itself but also other materials with a similar chemical structure that occur both naturally and can be synthesised in the lab, have been found to have a range of unusual physical properties such as superconductivity and ferroelectricity.

This makes them suitable for a range of applications, of which solar cells have emerged as the most prominent, with the potential to offer a low-cost, high-efficiency product – around at least 20% more than that of traditional silicon cells – that could boost the global renewables revolution.

But that potential has also come with challenges, in particular the stability of perovskites to the day-to-day environmental factors to which they must be subject, such as moisture, light and temperature.

No surprise then that the development of perovskites has seen, and is seeing, considerable investment and research interest along with the entry of new startups with the prospect of a major market opportunity.

Commercialising perovskite solar cells

Though they have yet to become fully commercialised, that day is not far off with Oxford PV, a spin-off from the University of Oxford in the UK, at the forefront after over a decade of developing the technology.

Oxford PV, founded in 2010 to advance solar PV but only latterly focussing exclusively on perovskites has pioneered the ‘tandem cell’ approach in which perovskite is added on top of conventional silicon solar cells to enhance their performance while maintaining the standard cell footprint.

In May 2023 Oxford PV recorded a record 28.6% cell conversion efficiency and in January 2024 a record panel efficiency of 25% compared with the averages for standard silicon cells and panels around 22 to 23%.

Moreover, Oxford PV’s theoretical maximum efficiency for its tandem cell approach is more than 40% compared with less than 30% for the standard cells.

“This new world record is a crucial milestone for Oxford PV, proving that our tandem solar cells can deliver record-breaking performance when assembled into solar panels,” said David Ward, CEO of Oxford PV, commenting in the January announcement that it is a first step in what should be a “transformative 2024”.

While R&D is continuing to improve the efficiency of the technology with a roadmap to go well beyond 30%, Oxford PV has reported starting production of its tandem cells at its Brandenburg-an-der-Havel site near Berlin in Germany – an acquisition of a former production site from Bosch Solar.

These are then expected to start coming to the market later in 2024, not directly but through their integration into modules of manufacturers in the market.

At the same time, Oxford PV is searching for a new high-volume manufacturing site with a particular eye on the US, where a subsidiary has been registered.

Perovskites in space

Just as perovskites are expected to become the solar PV product of choice for the next generation rooftop and utility-scale deployments, so too they are being eyed for use in space as an alternative to the go-to gallium arsenide cells.

Solar PV is essential in space for providing on-board power to orbiting satellites and for example the International Space Station. Gallium arsenide cells have become the technology of choice for their high absorption but more importantly, their ability to withstand the harsh space environment.

However, the main challenge with their use is the manufacturing costs primarily resulting from the scarcity of gallium and the more complex manufacturing process.

That is where perovskites are expected to have the potential to come in, because of their simpler manufacturing. Another key benefit is their versatility for diverse applications, from lightweight to bendable solar panels – a key factor for the proposed kilometre-scale satellites proposed to deliver solar energy to the Earth from space.

An understanding of the behaviour of perovskites in space is still ongoing, however.

In the Caltech space-based solar demonstrator which ran for most of 2023, the perovskite cells were found to exhibit marked variability in performance, whereas the low cost manufactured gallium arsenide cells had consistently performed well overall.

An earlier 10-month demonstration on the International Space Station also revealed some unusual properties about their absorption characteristics with varying temperature, with both a ‘self healing’ quality and enhanced light absorption that could make them particularly suitable for long-duration missions.

“A lot of people doubted that these materials could ever be strong enough to deal with the harsh environment of space,” said NASA research engineer Dr Lyndsey McMillon-Brown announcing the findings in May 2023, adding: “Not only do they survive, but in some ways, they thrived.”

With space technology developments often spinning off to Earth-based applications, this is a space to also keep watching.

And if you are involved in the development of perovskites, be sure to keep us updated with your findings.

Jonathan Spencer Jones

Specialist writer
Smart Energy International

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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.

The integration of Itron’s grid edge intelligence solutions to Schneider’s digital grid solutions aims to enable grid edge data analysis to optimise grid planning and operations to increase grid capacity while deferring infrastructure investments.

According to the companies, the integration is aimed to improve energy and grid management for utilities as homeowners and businesses increasingly adopt DERs, such as rooftop solar, battery energy storage, electric vehicles and microgrids at the grid edge.

In a joint release announcing the integration, the companies state that with more DERs coming online and more data being generated at the grid edge, the opportunity is provided to harness, aggregate and analyse that data to produce actionable insights for grid management.

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“We began collaborating with Schneider Electric to simplify grid management and enable a new generation of applications for utilities that recognise the dramatic changes and escalating demand that await all of us,” says Don Reeves, senior vice president of Outcomes at Itron.

“This collaboration will help us realise Itron’s vision for the grid edge – one where meters, transformers and feeders negotiate amongst themselves to achieve localised distribution outcomes, dynamically adapting and configuring sections of the distribution grid while enabling consumers to participate and benefit from these transactions.”

Ruben Llanes, NAM Power & Grid Segment president for Schneider Electric adds: “Utilities today need an interoperable, fully connected foundation for intelligent grid operations.”

Itron and Schneider Electric are also working on numerous integrated use cases that will deliver value across asset management, grid planning and operations and DER management and will work with utilities to integrate their solutions.

The partners cite Bloomberg NEF projections that 167 million homes and 23 million businesses will be solar users by 2050.

With the collaboration, they add, utilities can extend energy orchestration to behind-the-meter assets, enabling proactive management of grid constraints when and where needed.

The study, Online Detection of Winding Deformations in Large Power Transformers, aims to validate a detector prototype that can digitally and continuously monitor transformer voltage and current.

Already proven effective in a university setting, the transformer monitoring technique has been validated by computer simulation and bench testing on small transformers.

It will now be tested in the Power Authority’s Advanced Grid Innovations Laboratory for Energy (AGILe), which helps develop new technologies and demonstrate new solutions for energy systems.

If the NYPA-NYU project is successful, future phases could focus on field demonstration and commercialisation.

Transformer monitoring

AGILe simulates portions of New York State’s transmission grid and tests the impact of technologies and systems such as DERs, EVs, energy storage, cybersecurity, sensors and automation. The study will build 3D models for large power transformers and simulate deformations of winding disks.

According to the NYPA, the idea behind the detector is to continuously monitor online the voltage and currents of the transformer, and accurately calculate the leakage impedance of the transformer based on those measurements.

The proposed platform will then send an alarm to the operator when the transformer leakage reactance has changed more than the recommended 3% by Institute of Electrical and Electronics Engineers (IEEE) standards. This enables early detection of deformation in transformer windings due to forces and stresses from the short circuit events.

Normally, transformers need to be taken out of service for a Frequency Response Analysis (FRA) test to be performed. The proposed winding deformation detection technique would avoid disrupting the system operation, which is an expensive process.

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If successfully implemented, this new technology would avoid the cost of taking transformers offline to perform diagnostics to detect winding deformation, saving approximately $15,000 per day as well as preventing the cost of larger equipment failures that can cost up to $1.5 million per incident.

“Large power transformers are the backbone of electricity systems, designed to operate for decades,” said Francisco de Leon, NYU Tandon professor of electrical and computer engineering and member of NYU Tandon Power Lab.

“But unchecked accumulated mechanical deformations triggered by short circuits elsewhere in the system cause expensive repairs, lengthy downtime and even fire hazards. This collaboration with NYPA continues NYU Tandon Power Lab’s tradition of working in real world applications, in this case by creating technological safeguards to help identify when transformers need critical maintenance.”

NYSERDA-supported

The research is being supported by a nearly $190,000 grant from the New York State Energy Research and Development Authority (NYSERDA).

NYSERDA’s Electric Power Transmission and Distribution Future Grid Challenge programme supported the project with funding from the Clean Energy Fund.

Projects awarded under this initiative help establish a pathway for products and services to gain market entry by addressing existing technical and economic barriers within a specific challenge area associated with creating a high-performing, future grid.

Doreen M. Harris, president and CEO of NYSERDA said, “Modernising the state’s electric grid infrastructure is essential to ensuring the necessary capacity and transmission capabilities for continued reliability and resiliency.

“NYSERDA is pleased to support our sister agency in testing and advancing technology that can proactively identify potential issues with transformer operation without incurring costly maintenance outages as we transition to a dynamically managed zero-emission electric grid for New York State.”

The NYPA is the largest state public power organisation in the US, operating 16 generating facilities and more than 1,400 circuit miles of transmission lines.

More than 80% of the electricity NYPA produces is clean renewable hydropower. NYPA finances its operations with revenues earned in large part through sales of electricity.

According to Market Reports World, the global Home Energy Management Systems Market is expected to witness substantial growth from 2022 to 2028, reaching $3.5 billion by the end of the forecast period, up from $1.7 billion in 2021.

Fuelled by the increasing importance of intelligently managed energy efficiency for our power systems, the forecast for its growth is no surprise.

The potential of under-utilised sources of demand response within the residential sector has been a growing business interest as countries investigate newer, smarter ways of managing grid congestion.

What this has led to is a business battleground and, until recently, a largely fragmented market.

In one corner stand the original equipment manufacturers (OEMs) of clean tech assets, such as Heating, Ventilation and Air Conditioning (HVAC) systems, EVs and their charge points, as well as heat pumps and solar PV panels, to name some of the most popular.

In another are the optimisers and integrators, those companies who coordinate the flows of energy for optimal consumption, at times running interface with grid operators for demand response and flexibility services.

Then finally, we have the energy retailers, who buy electric power from generators at the wholesale level on behalf of their customers.

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For all these players, key to gaining market share will be convincing their customers that their products or services within the space are the most seamless.

For some, take market leaders such as Tesla or Octopus Energy, doing so largely on their own terms has been a very viable course of action.

But for others, whether HVAC providers, smart thermostat manufacturers or PV specialists and energy optimisers, more strategic footwork has been necessary, calling for acquisitions and strategic partnerships to consolidate their positions.

“The real war is about who will take ownership of being the ones that will convince the end customer to use their assets or their services.” So stated George Husni, LCP Delta’s head of business development.

Industry edge

According to Husni, in the battle between smart thermostat manufacturers and HVAC players, the former innovated user interfaces earlier giving them an edge, whereas “HVAC players lagged behind in developing the mobile application for end customers.

“We believe that within five years’ time integrated PV specialists, like 1KOMMA5°, as well as energy suppliers are expected to gain market share by offering a suit of solar-related offerings and innovative business models; smaller installers will be acquired and will phase out of distribution because they will not own the relationship with the final customers.”

Husni referenced key partnerships, acquisitions and strategic moves from the last quarter. Including a consolidation by emobility giant and Texas-based OEM Tesla, who has long dominated the EV realm, in 2023 they integrated the Powerwall system with their EV solar charging infrastructure.

In essence, Tesla owners using Tesla software, namely the Charge on Solar programme, can charge their vehicle using only excess solar power generated by their panels, alleviating stress from the grid of charging the EV and leading to a more energy-efficient home.

Tesla can thus be said to be a go-to case of an OEM leading the market on their own terms, consolidating their business across the Home Energy Management segment while maintaining their position as the EV leader.

Dominance in the realm also brings to mind the case of Octopus Energy, an energy supplier which, under its own retail brand, delivers customer service and energy products to 7.7 million households globally. Add in the influence of Kraken Technologies, Octopus’ tech arm and customer platform, and it is no wonder that the British player has been at the forefront of news headline the past few years.

According to Husni, there is a certain level of ‘concern’ about retailers in the market, about if and when they would decide to properly engage, as they already have an advantage from data and relationships from their customer base; a point made more pertinent by Octopus Energy’s stature.

But, of course, not everyone can be a Tesla or an Octopus.

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Home Energy Management: Consolidatory moves

Husni stressed key moves that have been needed by PV specialists in Europe, such as 1KOMMA5°’s acquisition of solar installers Zonduurzaam to enter the dutch market and experta solar to consolidate in Spain, as well as SolarEdge’s partnership with European heating manufacturer Vaillant to integrate Vaillant heat pumps into the SolarEdge Home ecosystem.

Further cases include the GridX and Sense partnership, focused on leveraging smart meters to provide consumers and utilities with better insights into energy usage and costs, as well as Sonnen integrating Nibe heat pumps into their virtual power plant programme.

On the energy supplier side, states Husni, Heatio partnered with E.on to provide its Energy as a Service solution through a home subscription product. The solution will integrate E.ON Next energy tariff and incentivises homeowners to improve the energy efficiency of their homes.

Take also Samsung’s smart home platform SmartThings, which partnered with energy related companies, such as Eve Systems in 2023 and British Gas earlier this year in January, to integrate products and track consumption.

In the partnership with Eve, SmartThings users will have the ability to reduce power consumption by monitoring individual devices that are connected to Eve’s smart plug, reducing utility bills by creating automation routines and setting timers to optimise energy usage.

The partnership with British Gas, described by British Gas’ parent company Centrica as “the exciting first step in a long-term venture”, sees British Gas’ PeakSave demand flexibility scheme integrate with SmartThings Energy, informing customers on the best times to use appliances to save money.

An energy integrator here, Samsung’s moves further cement its position in the market as an energy flow coordinator, interfacing both with energy companies and utilities to oversee consumption.

Such cases demonstrate the moves market players make to cement their position in the home energy management as it continues to consolidate. What are some of the key acquisitions and strategies you’ve witnessed within and think should be on our radar?

Let us know.

Cheers,
Yusuf Latief
Content Producer
Smart Energy International

Follow me on Linkedin

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.

According to the US-based research institute and consultancy, GETs, which are hardware and software solutions deployed within the transmission system, would help increase the capacity, flexibility and efficiency of the current grid.

The study, GETting Interconnected in PJM, finds that although GETs – including dynamic line ratings (DLRs), advanced power flow controls (PFCs) and topology optimisation (TO) – are becoming more widely studied and deployed in the US and internationally, they are not yet routinely considered in planning paradigms such as grid operators’ interconnection studies.

By freeing up additional transmission capacity for clean energy, 95 GETs projects considered in RMI’s analysis would generate approximately $1 billion in production cost savings per year for PJM, a regional transmission organisation (RTO).

“With growing demand for electricity to power our lives and an influx of clean energy projects under development, the US grid needs to expand, fast,” said Katie Siegner, an electric sector expert at RMI.

“Grid-enhancing technologies can be deployed in a matter of months and offer a multi-faceted solution – they unlock greater efficiency on the grid, keep electricity rates down, and enhance reliability throughout the energy transition.”

Interconnecting 6.6GW of projects by 2027

According to RMI’s study, GETs could facilitate the interconnection of 6.6GW of new wind, solar and storage generation across Illinois, Indiana, Ohio, Pennsylvania and Virginia that otherwise might have required prohibitively high-cost or time-consuming network upgrades.

For comparison, they add that in these five states, just over 2GW was connected to PJM’s grid in 2023.

Additionally, they state, that evaluating and deploying GETs as network upgrades would allow for faster and cheaper integration of large volumes of new generation. Traditional network upgrade costs have increased significantly in recent years — in PJM and elsewhere — as less and less hosting capacity is available on regional grids and more expensive upgrades are required.

RMI states in the study that transmission owners are now commonly identifying reconductoring or rebuilding affected transmission lines as such upgrades to address overloads triggered by interconnecting projects. However, GETs costs range from $272 to $523 million less than these types of network upgrades.

In addition to the cost savings, GETs significantly reduce the time required to connect new generation; reconductoring or rebuilding lines can take up to three years or more, adds RMI, while transmission owners can deploy GETs in months.

RMI adds that their analysis revealed significant savings that would flow to electricity consumers in the PJM region.

Specifically, within their production cost modelling analysis, RMI found that GETs-enabled new generators and reduced congestion would reduce energy production costs by just under $1 billion in 2027, ramping up to over $1 billion in savings per year by 2030.

Driven by lower OPEX of new renewable and storage resources, as well as the broader congestion relief that GETs provide, additional lower-cost generation would thus be enabled on PJM’s grid.

Recommendations

RMI comments in the study that, to further realise the potential of GETs, PJM should institute robust evaluation of the technologies across its interconnection and transmission planning practices and ensure its staff has the requisite training and modelling tools.

Transmission owners, they add, should build their internal capacity on GETs through studies and deployments, developers should propose and support GETs evaluation as network upgrades and state regulators should provide oversight and guidance to spur GETs adoption by their jurisdictional utilities.

Additionally, RMI states that the Federal Energy Regulatory Commission (FERC) should take additional steps to provide a comprehensive national regulatory framework that supports GETs adoption.

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Filings for GETs

According to the WATT (Working for Advanced Transmission Technologies) Coalition, RMI’s findings follow a filing from the PJM Interconnection to FERC on January 17, 2024, emphasising the value of DLR deployments during Winter Storm Elliot:

“The DLR ratings on this line during the storm proved higher than the ambient adjusted ratings PJM would have operated to otherwise. Had PJM not had the higher dynamic line ratings, PJM would have had to take action to re-dispatch the system to maintain reliability. Such action would have been very difficult under the critical operating conditions.”

PJM reaffirmed their support, states WATT, for a requirement for utilities to deploy DLR on all thermally constrained lines that lead to significant congestion and noted the need for application guides to facilitate utility adoption.

PPL Electric Utilities followed with their own filing to FERC on February 9, 2024, reporting that their DLR deployments have operated successfully since deployment – in one case eliminating congestion which was $12 million in summer 2022, and reducing congestion on another line from approximately $66 million to $1.6 million.

According to WATT, PPL Electric Utilities reported that they plan to install DLR on five more lines by the end of June this year.

Commenting in a release, Julia Selker, executive director of the WATT Coalition, said:

“It is very encouraging to see a system operator and utility sharing new information with FERC about the value of Dynamic Line Ratings. These comments show the substantial cost-saving and reliability benefits of DLR.

“The RMI study reminds us that it’s crucial to integrate all Grid Enhancing Technologies into utility practices to achieve the lowest-cost electricity system.

“I look forward to seeing compliance filings this spring in response to FERC’s Order 2023 on generator interconnection, which requires advanced power flow control and topology optimisation to be studied in interconnection processes and left DLR to the operator’s discretion.”

PJM Interconnection coordinates the movement of wholesale electricity in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia.

GETting interconnected was funded by Amazon and based on analysis conducted by Quanta Technologies.

Sentient Energy announced the solution, which they say is specifically designed to identify ground faults using autonomous line sensors. The feature significantly improves the accuracy of fault location, setting a new standard in outage management procedures, claims the Texas-based company, which develops grid solutions and services.

The new capability, announced as a major upgrade to the tech company’s Ample Analytics Platform, was initially developed with Alabama Power and implemented in a pilot programme.

Alabama Power has deployed over 2,000 intelligent line sensors and integrated sensor data into its Advanced Distribution Management System (ADMS) to refine distance-to-fault calculations.

By strategically placing three autonomous sensors at a location and utilising the Ample platform to create a virtual three-phase device, Alabama Power can now accurately identify ground faults, exceeding its target accuracy of 85%, says Sentient in a release. This has enabled Alabama Power to improve its response and restoration times.

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“Until now, line sensing technology was unable to accurately identify ground faults, creating potential errors in distance-to-fault calculations that depended on fault data. Our successful pilot programme with Alabama Power is a perfect example of how advanced analytics and sensor data improve the reliability and safety of power distribution,” stated Bob Karschnia, CEO of Sentient Energy.

“We are thrilled with the success of this pilot and look forward to implementing these technologies on a broader scale to continue improving the reliability and safety of our power grids.”

According to Sentient Energy, their Ample Analytics Platform predicts and prevents outages, detects faults, reports fault magnitudes and now distinguishes ground faults.

This enhanced fault detection and location capability is a vital component of the fault location, isolation, and service restoration (FLISR) application, they add, providing a swift solution that reduces System Average Interruption Duration Index (SAIDI) and Customer Minutes Interrupted (CMI), improving customer experience during outages.

Alabama Power, a subsidiary of Atlanta-based Southern Company, manages over 83,000 miles (133,575.55km) of power lines, providing electricity to 1.5 million customers across the state.

With the phase 2 plan, AES Ohio is proposing to continue the modernisation of its grid, which has been underway in the first phase, with a focus on the ongoing rollout of smart technologies to improve system stability and performance and the backbone communication capabilities.

At the foundation of the smart grid is smart meters and AES Ohio expects to have deployed these to 95% of customers by June 2025.

The smart grid phase 2 plan has three principal components – automation of distribution operations, advanced grid intelligence and telecommunications and cybersecurity.

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“We have a commitment to our customers and community to ensure the reliability and resiliency of our grid by making needed modernisation investments,” says Ken Zagzebski, President and CEO of AES Utilities.

“With the successful deployment of smart meters and mid-line reclosers in phase 1, customers are benefitting from fewer outages and decreased restoration times. The Smart Grid 2 plan is a critical step to an integrated grid and creating meaningful capability improvements that add value to our customers.”

The plan filings point to a number of challenges and opportunities that have driven the phase 2 vision.

These include fundamental changes in the energy industry that have created unprecedented strain on the nation’s power grid such as the rise of decarbonisation, the installation of utility-scale storage and renewables projects and the rapid adoption of customer-owned distributed resources.

In addition localised changes including more volatile weather, increasing adoption of EVs and growth from new industrial, commercial and residential customers have further increased the need for grid modernisation.

To achieve improved operational insights, AES Ohio is proposing investments in areas including dynamic network model optimisation, distributed energy resource management, the distribution performance monitoring and analytics centre and grid edge intelligence.

Regarding grid technology deployment, AES plans to continue to make investments in a self-healing grid, with a particular focus on grid automation, volt/var optimisation/conservation voltage reduction, an advanced distribution management system and field crew management.

To support the connectivity needs of the new technologies, such as the new substation and distribution devices, upgrades and expansion of the existing communication networks also are proposed, along with a strengthening of cybersecurity measures and optimising advanced threat readiness.

Positive benefits

In the filing, AES Ohio estimates a 3.6 to 1 NPV benefits-to-cost ratio of the investments over 20 years, with most indirect in the form of reduced CO2 emissions and economic impact but almost a third direct, including avoided or deferred capital spend, operations and maintenance and energy and demand savings and enhanced reliability.

AES Ohio has requested an order on the plan in Q1 of 2025 to enable smooth transition between the two phases but also in the anticipation of maintaining on-site the same contractors working on the phase 1 investments.

AES Ohio serves more than 527,000 customer accounts in west central Ohio.

Avangrid, which owns and operates eight electric and natural gas utilities, serving more than 3.3 million customers in New York and New England, said in a release that the project will deploy the robot dog to complete visual and thermal inspections at two substations of its Connecticut subsidiary, United Illuminating (UI).

The project will take place at UI’s Singer and East Shore substations and test a variety of AI models, developed by Levatas, to read analogue gauges, record thermal images and detect damaged equipment.

To do so, the robot dog—nicknamed Sparky by the Avangrid team—is outfitted with a camera that has a 30 times optical zoom and an infrared camera capable of taking thermal readings to compare the transformer and breaker phases.

There is also an option to attach an acoustic sensor that can detect, locate and visualise changes in sound signatures, malfunctioning equipment and other noise anomalies in real time. The robot also has a core processor to enhance autonomous navigation and communications.

At the Singer substation, the project will test how quickly and accurately the robot can detect and read several of the substation’s analogue gauges. At East Shore substation, the project will test the robot’s ability to inspect transformers, circuit breakers and capacitor banks.

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Initially, the robot will be controlled by an onsite operator using a tablet, which can be used to both drive the robot and create autonomous missions. Avangrid is also working to install software that would allow for remote operation as well.

“We’re very proud to once again be among the utility industry pioneers pushing the boundaries of technology,” said Pedro Azagra, Avangrid CEO.

“Last year, we announced the establishment of an in-house team to build unique machine learning models to increase reliability. With this pilot project, we are now exploring using AI in another aspect of our business where there is great potential to bring high value to our customers and stakeholders. This type of innovation will help us be more efficient, target our investments and increase reliability for our customers.”

“It’s amazing to see this technology, which was inconceivable a few years ago, in our hands bringing value and benefits to our customers,” added Catherine Stempien, Avangrid Networks President and CEO.

“While there will be many benefits, most important is that we expect Sparky will increase the frequency of our substation inspections so that we can see how our equipment is functioning during different seasons, times of the day and energy loads. With this increased amount of data, we will have the potential to proactively identify unknown issues and trends before they cause outages that impact our customers. This is a great example of innovation and technology helping us do more.”

From Spot to Sparky

According to a spokesperson from Avangrid, Sparky improves on Spot in that it will be trained to live and operate within an energised substation environment and will be taught to identify abnormal conditions within that space.

Using machine learning algorithms, Avangrid has collaborated with Levatas to create an insulator inspection model that will use one of Sparky’s cameras to look for, identify and report insulator anomalies.

It will have the ability to digitise analogue gauges to keep track of important equipment health indicators and create alarms and notifications.

Sparky also has a thermal camera that it will use to inspect for thermal hotspots on substation equipment, giving operations personnel the opportunity to manage those issues promptly and efficiently.

The spokesperson added that, as with AI models, they expect the machine learning algorithms to improve with time, making the solution more valuable.

“The gauge reading model, for example, has been successful in flagging health indicators out of pre-defined thresholds and acceptable range. We are pleased with the results so far and are excited to continue with Sparky’s integration into our day-to-day operations and maintenance programs.

“Currently, we do not have a specific timeline for deployment of Sparky. At this time, we are focused on developing its application model, including its operational space, data management and communication protocols.”