KUB looks at peak power demand

Ireland 65% Renewable Grid Capability showcases world leading integration of intermittent wind and solar, smart grid flexibility, EU-SysFlex learnings, and the Celtic Interconnector to enhance stability, exports, and energy security across the European grid.

Key Points

Ireland can run its isolated power system with 65% variable wind and solar, informing EU grid integration and scaling.

✅ 65% system non-synchronous penetration on an isolated grid

✅ EU-SysFlex roadmap supports large-scale renewables integration

✅ Celtic Interconnector adds 700MW capacity and stability

Ireland is now able to cope with 65% of its electricity coming from intermittent electricity sources like wind and solar, as highlighted by Ireland's green electricity outlook today – an expertise Energy Minister Denish Naugthen believes can be replicated on a larger scale as Europe moves towards 50% renewable power by 2030.

Denis Naughten is an Irish politician who serves as Minister for Communications, Climate Action and Environment since May 2016.

Naughten spoke to editor Frédéric Simon on the sidelines of a EURACTIV event in the European  Parliament to mark the launch of EU-SysFlex, an EU-funded project, which aims to create a long-term roadmap for the large-scale integration of renewable energy on electricity grids.

What is the reason for your presence in Brussels today and the main message that you came to deliver?

The reason that I’m here today is that we’re going to share the knowledge what we have developed in Ireland, right across Europe. We are now the global leaders in taking variable renewable electricity like wind and solar onto our grid.

We can take a 65% loading on to the grid today – there is no other isolated grid in the world that can do that. We’re going to get up to 75% by 2020. This is a huge technical challenge for any electricity grid and it’s going to be a problem that is going to grow and grow across Europe, even as Europe's electricity demand rises in the coming years, as we move to 50% renewables onto our grid by 2030.

And our knowledge and understanding can be used to help solve the problems right across Europe. And the sharing of technology can mean that we can make our own grid in Ireland far more robust.

What is the contribution of Ireland when it comes to the debate which is currently taking place in Europe about raising the ambition on renewable energy and make the grid fit for that? What are the main milestones that you see looking ahead for Europe and Ireland?

It is a challenge for Europe to do this, but we’ve done it Ireland. We have been able to take a 65% loading of wind power on our grid, with Irish wind generation hitting records recently, so we can replicate that across Europe.

Yes it is about a much larger scale and yes, we need to work collaboratively together, reflecting common goals for electricity networks worldwide – not just in dealing with the technical solutions that we have in Ireland at the fore of this technology, but also replicating them on a larger scale across Europe.

And I believe we can do that, I believe we can use the learnings that we have developed in Ireland and amplify those to deal with far bigger challenges that we have on the European electricity grid.

Trialogue talks have started at European level about the reform of the electricity market. There is talk about decentralised energy generation coming from small-scale producers. Do you see support from all the member states in doing that? And how do you see the challenges ahead on a political level to get everyone on board on such a vision?

I don’t believe there is a political problem here in relation to this. I think there is unanimity across Europe that we need to support consumers in producing electricity for self-consumption and to be able to either store or put that back into the grid.

The issues here are more technical in nature. And how you support a grid to do that. And who actually pays for that. Ireland is very much a microcosm of the pan-European grid and how we can deal with those challenges.

What we’re doing at the moment in Ireland is looking at a pilot scheme to support consumers to generate their own electricity to meet their own needs and to be able to store that on site.

I think in the years to come a lot of that will be actually done with more battery storage in the form of electric vehicles and people would be able to transport that energy from one location to another as and when it’s needed. In the short term, we’re looking at some novel solutions to support consumers producing their own electricity and meeting their own needs.

So I think this is complex from a technical point of view at the moment, I don’t think there is an unwillingness from a political perspective to do it, and I think working with this particular initiative and other initiatives across Europe, we can crack those technical challenges.

To conclude, last year, the European Commission allocated €4 million to a project to link up the Irish electricity grid to France. How is that going to benefit Ireland? And is that related to worries that you may have over Brexit?

The plan, which is called the Celtic Interconnector, is to link France with the Irish electricity grid. It’s going to have a capacity of about 700MW. It allows us to provide additional stability on our grid and enables us to take more renewables onto the grid. It also allows us to export renewable electricity onto the main European grid as well, and provide stability to the French network.

So it’s a benefit to both individual networks as well as allowing far more renewables onto the grid. We’ve been working quite closely with RTE in France and with both regulators. We’re hoping to get the support of the European Commission to move it now from the design stage onto the construction stage. And I understand discussions are ongoing with the Commission at present with regard to that.

And that is going to diversify potential sources of electricity coming in for Ireland in a situation which is pretty uncertain because of Brexit, correct?

Well, I don’t think there is uncertainty because of Brexit in that we have agreements with the United Kingdom, we’re still going to be part of the broader energy family in relation to back-and-forth supply across the Irish Sea, with grid reinforcements in Scotland underscoring reliability needs.  But I think it is important in terms of meeting the 15% interconnectivity that the EU has set in relation to electricity.

And also in relation of providing us with an alternative support in relation to electricity supply outside of Britain. Because Britain is now leaving the European Union and I think this is important from a political point of view, and from a broader energy security point of view. But we don’t see it in the short term as causing threats in relation to security of supply.

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Virtual Power Plants orchestrate distributed energy resources like rooftop solar, home batteries, and EVs to deliver grid services, demand response, peak shaving, and resilience, lowering costs while enhancing reliability across wholesale markets and local networks.

Key Points

Virtual Power Plants aggregate solar and batteries to provide grid services, cut peak costs, and boost reliability.

✅ Aggregates DERs via cloud to bid into wholesale markets

✅ Reduces peak demand, defers costly grid upgrades

✅ Enhances resilience vs outages, cyber risks, and wildfires

If “virtual” meetings can allow companies to gather without anyone being in the office, then remotely distributed solar panels and batteries can harness energy and act as “virtual power plants.” It is simply the orchestration of millions of dispersed assets within a smarter electricity infrastructure to manage the supply of electricity — power that can be redirected back to the grid and distributed to homes and businesses. 

The ultimate goal is to revamp the energy landscape, making it cleaner and more reliable. By using onsite generation such as rooftop solar and smart solar inverters in combination with battery storage, those services can reduce the network’s overall cost by deferring expensive infrastructure upgrades and by reducing the need to purchase cost-prohibitive peak power. 

“We expect virtual power plants, including aggregated home solar and batteries, to become more common and more impactful for energy consumers throughout the country in the coming years,” says Michael Sachdev, chief product officer for Sunrun Inc., a rooftop solar company, in an interview. “The growth of home solar and batteries will be most apparent in places where households have an immediate need for backup power, as they do in California, where grid reliability pressures have led utilities to turn off the electricity to reduce wildfire risk.”

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Home battery adoption, such as Tesla Powerwall systems, is becoming commonplace in Hawaii and in New England, he adds, because those distributed assets are improving the efficiency of the electrical network. It is a trend that is reshaping the country’s energy generation and delivery system by relying more on clean onsite generation and less on fossil fuels.

Sunrun has recently formed a business partnership with AutoGrid, which will manage Sunrun’s fleet of rechargeable batteries. It is a cloud-based system that allows Sunrun to work with utilities to dispatch its “storage fleet” to optimize the economic results. AutoGrid compiles the data and makes AI-driven forecasts that enable it to pinpoint potential trouble spots. 

But a distributed energy system, or a virtual power plant, would have 200,000 subsystems. Or, 200,000 5 kilowatt batteries would be the equivalent of one power plant that has a capacity of 1,000 megawatts. 

“A virtual power plant acts as a generator,” says Amit Narayan, chief executive officer of AutoGrid, in an interview. “It is one of the top five innovations of the decade. If you look at Sunrun, 60% of every solar system it sells in the Bay Area is getting attached to a battery. The value proposition comes when you can aggregate these batteries and market them as a generation unit. The pool of individual assets may improve over time. But when you add these up, it is better than a large-scale plant. It is like going from mainframe computers to laptops.”

The AutoGrid executive goes on to say that centralized systems are less reliable than distributed resources. While one battery could falter, 200,000 of them that operate from remote locations will prove to be more durable — able to withstand cyber attacks and wildfires. Sunrun’s Sachdev adds that the ability to store energy in batteries, as seen in California’s expanding grid-scale battery use supporting reliability, and to move it to the grid on demand creates value not just for homes and businesses but also for the network as a whole.

The good news is that the trend worldwide is to make it easier for smaller distributed assets, including energy storage for microgrids that support local resilience, to get the same regulatory treatment as power plants. System operators have been obligated to call up those power supplies that are the most cost-effective and that can be easily dispatched. But now regulators are giving virtual power plants comprised of solar and batteries the same treatment. 

In the United States, for example, the Federal Energy Regulatory Commission issued an order in 2018 that allows storage resources to participate in wholesale markets — where electricity is bought directly from generators before selling that power to homes and businesses. Under the ruling, virtual power plants are paid the same as traditional power suppliers. A federal appeals court this month upheld the commission’s order, saying that it had the right to ensure “technological advances in energy storage are fully realized in the marketplace.” 

“In the past, we have used back-up generators,” notes AutoGrid’s Narayan. “As we move toward more automation, we are opening up the market to small assets such as battery storage and electric vehicles. As we deploy more of these assets, there will be increasing opportunities for virtual power plants.” 

Virtual power plants have the potential to change the energy horizon by harnessing locally-produced solar power and redistributing that to where it is most needed — all facilitated by cloud-based software that has a full panoramic view. At the same time, those smaller distributed assets can add more reliability and give consumers greater peace-of-mind — a dynamic that does, indeed, beef-up America’s generation and delivery network.

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Alberta Electricity Market Reforms aim to boost grid reliability and efficiency through a day-ahead market, transmission policy changes, clearer pricing signals, AESO oversight, and smarter siting near existing infrastructure to lower consumer costs.

Key Points

Policies add a day-ahead market and transmission fees to modernize the grid and improve reliability.

✅ Day-ahead market for clearer pricing and scheduling

✅ Up-front, non-refundable transmission payments by generators

✅ AESO to draft new rules by end of 2025

The Alberta government is implementing significant electricity policy changes to its electricity market to enhance system reliability and efficiency. These reforms aim to modernize the grid, accommodate growing energy demands, and align with best practices observed in other jurisdictions.

Proposed Market Reforms

The government has outlined several key initiatives:

• Day-Ahead Market Implementation: Introducing a day-ahead market is intended to provide clearer pricing signals and improve the scheduling of electricity generation. This approach allows market participants to plan and commit to energy production in advance, enhancing grid stability.

• Transmission Policy Revisions: The government proposes reforms to transmission policies, including the introduction of up-front and non-refundable transmission payments from new power generators. These payments would vary based on the proximity of new generators to existing transmission lines with available capacity. As part of a broader market overhaul, this strategy encourages the development of power plants in areas where existing infrastructure can be utilized, potentially reducing costs for consumers and businesses.

Government's Objectives

Minister of Affordability and Utilities, Nathan Neudorf, emphasized that these changes are necessary to meet growing energy demands and modernize Alberta’s electricity system. The government's goal is to create a more reliable and efficient electrical system that benefits both consumers and the broader economy.

Industry Reactions

The proposed reforms have elicited mixed reactions from industry stakeholders amid profound sector change across Alberta:

• Renewable Energy Sector Concerns: The Canadian Renewable Energy Association (CanREA) has expressed concerns about the potential for punitive market and transmission changes, and some retailers have similarly urged caution. They advocate for policies that support the integration of renewable energy sources and ensure fair treatment within the market.

• Regulatory Oversight: The Alberta Electric System Operator (AESO) is tasked with preparing restructured energy market rules by the end of 2025. This timeline reflects the government's commitment to a thorough and consultative approach to market reform.

Implications for Consumers

The Alberta government's proposed market changes aim to enhance the reliability and efficiency of the electricity system by considering measures such as a Rate of Last Resort to provide additional stability. By encouraging the development of power plants in areas with existing infrastructure, the reforms seek to reduce costs for consumers and businesses. However, the success of these initiatives will depend on careful implementation and ongoing engagement with all stakeholders to balance the diverse interests involved.

Alberta's proposed electricity market reforms represent a significant step toward modernizing the province's energy infrastructure. By introducing a day-ahead market and revising transmission policies, the government aims to create a more reliable and efficient electrical system and promote market competition more effectively. While these changes have generated diverse reactions, they underscore the government's commitment to addressing the evolving energy needs of Alberta's residents and businesses.

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Ukraine nuclear safety risks escalate as IAEA warns of power grid attacks threatening reactor cooling, diesel generators, and Zaporizhzhia oversight, prompting UN calls for demilitarized zones to prevent radioactive releases and accidents.

Key Points

Escalating threats from grid attacks and outages that jeopardize reactor cooling, IAEA oversight, and public safety.

✅ Power grid strikes threaten reactor cooling systems.

✅ Emergency diesel generators are last defense lines.

✅ Calls grow for demilitarized zones around plants.

In early February 2025, Rafael Grossi, Director General of the International Atomic Energy Agency (IAEA), expressed grave concerns regarding the safety of Ukraine's nuclear facilities amid ongoing Russian attacks on the country's power grids, as Kyiv warned of a difficult winter without power after deadly strikes on energy infrastructure. Grossi's warnings highlight the escalating risks to nuclear safety and the potential for catastrophic accidents.

The Threat to Nuclear Safety

Ukraine's nuclear infrastructure, including the Zaporizhzhia Nuclear Power Plant—the largest in Europe—relies heavily on a stable power supply to maintain critical cooling systems and other safety measures. Russian military operations targeting Ukraine's energy infrastructure have led to power outages, and created hazards akin to those highlighted in downed power line safety guidance during emergency repairs, jeopardizing the safe operation of these facilities. Grossi emphasized that such disruptions could result in severe nuclear accidents if cooling systems fail.

IAEA's Response and Actions

In response to these threats, the IAEA has been actively involved in monitoring and assessing the situation. Grossi visited Kyiv to inspect electrical substations and discuss safety measures with Ukrainian officials. He underscored the necessity of ensuring uninterrupted power to nuclear plants and the critical role of emergency diesel generators as a last line of defense, and noted that maintaining staffing continuity, including measures such as staff living on site at critical facilities, may be necessary. The IAEA has also postponed the rotation of its mission at the Zaporizhzhia plant due to security concerns, as reported by Reuters.

International Concerns and Diplomatic Efforts

The international community has expressed deep concern over the potential for nuclear accidents in Ukraine, echoing earlier grid overseer warnings about systemic risks in other crises that stress energy systems. The United Nations and various countries have called for the establishment of a demilitarized zone around nuclear facilities to prevent military activities that could compromise their safety. Diplomatic efforts are ongoing to facilitate dialogue between Russia and Ukraine, aiming to ensure the protection of nuclear sites and the safety of surrounding populations.

The Zaporizhzhia Nuclear Power Plant

The Zaporizhzhia Nuclear Power Plant, located in southeastern Ukraine, has been under Russian control since early in the conflict, with Rosatom cooperation agreements reflecting broader nuclear policy priorities that frame Moscow's approach to the sector. The plant consists of six reactors and has been a focal point of international concern due to its size and the potential consequences of any incident. The IAEA has been working to maintain oversight and ensure the plant's safety amid the ongoing conflict.

Potential Consequences of Nuclear Accidents

A nuclear accident at any of Ukraine's nuclear facilities could have catastrophic consequences, including the release of radioactive materials, displacement of populations, and long-term environmental damage, with communities potentially facing weeks without electricity and basic services in the aftermath. The proximity of these plants to densely populated areas further amplifies the risks. The international community continues to monitor the situation closely, emphasizing the need for immediate action to safeguard nuclear facilities.

The ongoing conflict in Ukraine has introduced unprecedented challenges to nuclear safety. The IAEA's warnings and actions underscore the critical need for international cooperation to protect nuclear facilities from the dangers posed by military activities. Ensuring the safety of these sites is paramount to prevent potential disasters that could have far-reaching humanitarian and environmental impacts, and sustained attention to nuclear workers' safety concerns helps maintain operational readiness under strain.

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Manitoba Clean Electricity Investment will upgrade hydroelectric turbines, expand a 230 kV transmission network, and deliver reliable, affordable low-carbon power, reducing greenhouse gas emissions and strengthening grid reliability across Portage la Prairie and Winnipeg River.

Key Points

Joint federal-provincial funding to upgrade hydro turbines and build a 230 kV grid, boosting reliable, low-carbon power.

✅ $314M for new turbines at Pointe du Bois (+52 MW capacity)

✅ $161.6M for 230 kV transmission in Portage la Prairie

✅ Cuts Brandon Generating Station emissions by ~37%

The governments of Canada and Manitoba have announced a joint investment of $475.6 million to strengthen Manitoba’s clean electricity grid that can support neighboring provinces with clean power and ensure continued supply of affordable and reliable low-carbon energy.

This federal-provincial investment provides $314 million for eight new hydroelectric turbines at the 75 MW Pointe du Bois Generating Station on the Winnipeg River, as well as $161.6 million to build a new 230 kV transmission network in the Portage la Prairie area, bolstering power sales to SaskPower and regional reliability.

The $314 million joint investment in the Pointe du Bois Renewable Energy Project includes $114.1 million from the Government of Canada and nearly $200 million from the Government of Manitoba. The joint investment will enable Manitoba Hydro to replace eight generating units that are at the end of their lifecycle, amid looming new generation needs for the province. The new, more efficient units will increase the capacity of the Pointe du Bois generating station by 52 MW.

The $161.6 million joint investment in the Portage Area Capacity Enhancement project includes $70.9 million from the Government of Canada and $90.6 million from the Government of Manitoba. The joint investment will support the construction of a new transmission line to enhance reliability for customers across southwest Manitoba and help Manitoba Hydro meet increasing demand, with projections that demand could double over the next two decades. By decreasing Manitoba’s reliance on its last grid-connected fossil-fuel generating station, this investment will reduce greenhouse gas emissions at the Brandon Generating Station by about 37%.

The federal government’s total contribution of $184.9 million is provided through the Green Infrastructure Stream of the Investing in Canada Plan, alongside efforts to improve interprovincial grid integration such as NB Power agreements with Hydro-Quebec that strengthen regional reliability. This federal funding is conditional on meeting Indigenous consultation requirements, as well as environmental assessment obligations. Including today’s announcement, the Green Infrastructure Stream has supported 38 infrastructure projects in Manitoba, for a total federal contribution of more than $766.8 million and a total provincial contribution of over $658.4 million.

“A key part of our economic plan is making Canada a clean electricity superpower. Today’s announcement in Manitoba will deliver clean, reliable, and affordable electricity to people and businesses across the province—and we will continue working to expand our clean electricity grid and create great careers for people from coast to coast to coast,” said Deputy Prime Minister and Finance Minister Chrystia Freeland.

The federal government will continue to invest in making Canada a clean electricity superpower, supporting provincial initiatives like Hydro-Quebec's fossil-free strategy that complement these investments to ensure Canadians from coast to coast to coast have the affordable and reliable clean electricity they need today and for generations to come.

“Manitoba Hydro is extremely pleased to be receiving this federal funding through the Green Infrastructure Stream of the Investing in Canada Infrastructure Program. The investments we are making in both these critical infrastructure projects will help provide Manitobans with energy for life and power our province’s economic growth with clean, reliable, renewable hydroelectricity. These projects build on our legacy of investments in renewable energy over the past 100 years, as we work towards a lower carbon future for all Manitobans,” said Jay Grewal, president and chief executive officer of Manitoba Hydro.

About 97% of Manitoba’s electricity is generated from clean hydro, with most of the remaining 3% coming from wind generation. Manitoba’s abundant clean electricity has resulted in Manitobans paying 9.455 ¢/kWh — the second-lowest electricity rate in Canada, though limits on serving new energy-intensive customers have been flagged recently.

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BC-Alberta Electricity Restrictions spotlight interprovincial energy tensions, limiting power exports and affecting grid reliability, energy sharing, and climate goals, while raising questions about federal-provincial coordination, smart grids, and storage investments.

Key Points

Policies limiting Alberta's power exports to provinces like BC, prioritizing local demand and affecting grid reliability.

✅ Prioritizes Alberta load over interprovincial power exports

✅ Risks to BC peak demand support and outage resilience

✅ Pressures for federal-provincial coordination and smart-grid investment

In a move that underscores the complexities of Canada's interprovincial energy relationships, the government of British Columbia (B.C.) has formally expressed concerns over recent electricity restrictions imposed by Alberta after it suspended electricity purchase talks with B.C., amid ongoing regional coordination challenges.

Background: Alberta's Electricity Restrictions

Alberta, traditionally reliant on coal and natural gas for electricity generation, has been undergoing a transition towards more sustainable energy sources as it pursues a path to clean electricity in the province.

In response, Alberta introduced restrictions on electricity exports, aiming to prioritize local consumption and stabilize its energy market and has proposed electricity market changes to address structural issues.

B.C.'s Position: Ensuring Energy Reliability and Cooperation

British Columbia, with its diverse energy portfolio and commitment to sustainability, has historically relied on the ability to import electricity from Alberta, especially during periods of high demand or unforeseen shortfalls. The recent restrictions threaten this reliability, prompting B.C.'s government to take action amid an electricity market reshuffle now underway.

B.C. officials have articulated that access to Alberta's electricity is crucial, particularly during outages or times when local generation does not meet demand. The ability to share electricity among provinces ensures a stable and resilient energy system, benefiting consumers and supporting economic activities, including critical minerals operations, that depend on consistent power supply.

Moreover, B.C. has expressed concerns that Alberta's restrictions could set a precedent that might affect future interprovincial energy agreements. Such a precedent could complicate collaborative efforts aimed at achieving national energy goals, including sustainability targets and infrastructure development.

Broader Implications: National Energy Strategy and Climate Goals

The dispute between B.C. and Alberta over electricity exports highlights the absence of a cohesive national energy strategy, as external pressures, including electricity exports at risk, add complexity. While provinces have jurisdiction over their energy resources, the interconnected nature of Canada's power grids necessitates coordinated policies that balance local priorities with national interests.

This situation also underscores the challenges Canada faces in meeting its climate objectives. Transitioning to renewable energy sources requires not only technological innovation but also collaborative policies that ensure energy reliability and affordability across provincial boundaries, as rising electricity prices in Alberta demonstrate.

Potential Path Forward: Dialogue and Negotiation

Addressing the concerns arising from Alberta's electricity restrictions requires a nuanced approach that considers the interests of all stakeholders. Open dialogue between provincial governments is essential to identify solutions that uphold the principles of energy reliability, economic cooperation, and environmental sustainability.

One potential avenue is the establishment of a federal-provincial task force dedicated to energy coordination. Such a body could facilitate discussions on resource sharing, infrastructure investments, and policy harmonization, aiming to prevent conflicts and promote mutual benefits.

Additionally, exploring technological solutions, such as smart grids and energy storage systems, could enhance the flexibility and resilience of interprovincial energy exchanges. Investments in these technologies may reduce the dependency on traditional export mechanisms, offering more dynamic and responsive energy management strategies.

The tensions between British Columbia and Alberta over electricity restrictions serve as a microcosm of the broader challenges facing Canada's energy sector. Balancing provincial autonomy with national interests, ensuring equitable access to energy resources, and achieving climate goals require collaborative efforts and innovative solutions. As the situation develops, stakeholders across the political, economic, and environmental spectrums will need to engage constructively, fostering a Canadian energy landscape that is resilient, sustainable, and inclusive.

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