Electrical Engineering Power Systems

Virtual Power Plants (VPPs) have been around for a long time as a concept. After China has seen a rise in their use will the US be next? By digitally aggregating thousands—often millions—of flexible assets like heat pumps, EV chargers, batteries, smart thermostats, and commercial HVAC, VPPs deliver reliable capacity, balancing, and ancillary services at a fraction of the cost and carbon of traditional peaker plants, without compromising comfort or productivity. As electrification accelerates and variable renewables scale, grid stress is rising, and building new firm capacity is expensive and slow; unlocking demand-side flexibility is faster, cleaner, and more scalable. The enabling technologies exist today—smart, standards-based controls—and policy is beginning to catch up. Priority actions are clear: pay-for-performance markets that let flexibility compete fairly with supply-side resources, interoperability through open standards to reduce costs and avoid lock-in, and consumer-first participation models with simple enrollment, strong privacy by default, and equitable access, particularly for low-income customers.

Why are European power prices so high? Both wholesale and final prices are higher in Europe then elsewhere • E.g., wholesale prices are 70% in Germany than in Texas The reason for higher wholesale prices is *not* marginal pricing (the “merit order”) • All other power markets power markets apply the same price logic of price formation, including Texas The true reasons are simple: gas and carbon • Gas is more expensive in Europe  • We price carbon, America does not • These two commodity prices easily explain the entire wholesale price gap The wholesale prices is only part of the picture – what also matters: • Grid costs recovered through grid tariff • Subsidies recovered from taxpayers How policy choices have inflated power system costs • Large investment in expensive power generation (small-scale solar, biogas, offshore wind) • Delayed and expensive grid expansion (underground cables) • Barriers to smart electricity consumption (delayed and expensive smart meters, harmful subsidies) • Lack of locational prices (resulting in curtailment and grid congestion costs) • Decommissioning existing assets before end of lifetime (coal, nuclear) • Self-consumption (solar & batteries in homes, fossil plants in industry), driving up the cost for everyone else There has been reasons for this • People want to have solar panels on their rooftop, they don’t like to see transmission towers, and they are scared of nuclear, etc. • But nevertheless: these choices have driven up the costs of the power system 👉 Looking forward: what can be done Not an option: inventing a new “pricing rule” • Replace marginal pricing (“getting rid of the merit order”) with something else will create chaos, not lower prices Pathway 1: scale back on climate ambition • Lower the carbon price & reduce renewables targets • This will bring down power prices … • … at the cost of higher emissions and more climate change Pathway 2: do things better • Focus on low-cost investment options: large solar farms not small rooftop, overhead lines not underground cables, fossil gas rather not hydrogen, solar not biogas, utility-scale not small batteries, etc. • Improve market design: prices should reflect marginal costs (split bidding zones, grid tariff reform, dynamic pricing, digitalization, production-independent CfDs, etc.)

#HeideHub, #NordWestHub and #NordHub are the names of unique electricity hubs being created in our grid that will interconnect #HVDC systems in the future. They will strengthen the German electricity #grid and enable an even more efficient integration of #renewableenergy. Securing the sites is an important milestone for TenneT Germany on the road to the start of construction in 2026! The #NorthSea offers enormous potential for #windenergy generation. We reliably bring this electricity to the consumption centers in southern and western Germany. To do this, we rely on modern direct current (DC) technology, which is ideally suited for low-loss transmission over long distances. The catch so far: DC lines can only be implemented as point-to-point connections. #Multiterminal hubs are fundamentally changing this. They create the conditions for transporting large amounts of electricity flexibly and in line with demand over long distances. By linking DC lines, they enable a new grid level – the DC overlay grid. A DC integrated grid that complements and relieves the existing AC grid. In a future Europe-wide DC overlay grid, large amounts of electricity from renewable sources can be traded across borders and efficiently transported from the point of generation to where it is needed. A central building block for the energy supply of the future – independent, resilient, affordable and climate-neutral.   #LightingTheWayAheadTogether 50Hertz Transmission GmbH, Amprion GmbH

🔴 The Spanish power system collapsed within seconds following a double contingency in its interconnection lines with France. First, a 400 kV line disconnected, and less than a second later, a second line also failed, suddenly isolating Spain while it was exporting 5 GW of power. The frequency rose abruptly, triggering the automatic disconnection of approximately 10 GW of renewable generation, programmed to shut down when exceeding 50.2 Hz. This led to a sudden energy shortfall, a sharp frequency drop, and within just nine seconds, a total system blackout. 🪕 The causes of the incident are attributed to low rotational inertia (only about 10 GW of synchronous generation online), identically configured renewable protections that reacted simultaneously, reserves that were inadequate for such a high share of renewables, and an under-dimensioned interconnection with France. Could this have been avoided? Several measures could help prevent similar situations in the future, such as requiring synthetic inertia in large power plants, reinforcing the interconnection with France, and establishing a fast frequency response market, among others. 💡 In this context, Battery Energy Storage Systems (BESS) are more essential than ever. These systems can provide synthetic inertia, ultra-fast frequency response, and backup power in critical situations—capabilities that today’s renewable-dominated system cannot ensure on its own. By reacting in milliseconds, BESS help stabilize the grid during sudden frequency deviations, preventing massive disconnections and buying time for other reserves to activate. Their strategic deployment, combined with appropriate regulation, would make these systems a cornerstone of a more secure and resilient future power system. ... ✋️Please note that this post was written based on the information published on or before its release. Root cause analysis is still ongoing and updates will be released with the outcomes of the investigation. The goal is to show the features that can be provided by BESS within the wide portfolio of solutions applicable in these cases. All inisghts are highly welcome and appreciated in order to enrich our collective understanding. ... 📸 Reid Gardner Battery Energy Storage System (Nevada, USA) A real-world example of how BESS ensures grid stability by delivering synthetic inertia and fast frequency response—essential in a renewable-heavy energy mix.

🔋 Why Grid Frequency Matters – and How Inertia Keeps the Lights On Did you know that the stability of our entire power grid depends on keeping frequency within ±0.1 Hz of its target value (50 Hz or 60 Hz worldwide)? If it drifts ±0.5 Hz outside the norm, grids enter emergency mode, risking blackouts. A more extreme deviation? It could lead to a full system failure—costing economies millions and endangering lives. At the heart of frequency stability is inertia—the kinetic energy stored in the spinning turbines of synchronous generators. This “rotating mass” acts like a shock absorber, slowing down frequency changes when sudden disruptions occur (like losing a 1 GW power plant). 🛁 Imagine it like a bathtub: The tap = power generation (flowing in) The drain = consumption (flowing out) The water level = frequency The size of the tub = inertia As long as inflow and outflow are equal, the water level (frequency) stays stable. But if the flow changes? The level moves. And the bigger the tub (more inertia), the slower and smaller the change. ⚡️ As we transition to renewables (which often lack inherent inertia), maintaining frequency stability becomes even more challenging, and innovative solutions are needed to “artificially” replicate inertia in modern grids. 👉 What role do you see for battery storage, synthetic inertia, or demand response in solving this challenge? Let’s talk about the future of grid stability. #Energy #PowerSystems #GridFrequency #Inertia #Renewables #Electricity #SmartGrid #EnergyTransition #PowerQuality

⚡️ LCOE vs. System-LCOE: Why understanding the full picture matters! As part of Norway’s efforts to promote smart, sustainable energy solutions abroad, we often highlight how competitive solar, wind, and offshore technologies have become. The progress is real, costs have dropped, and renewables are at the heart of the global energy transition. But when planning large-scale investments or national energy strategies, headline figures alone aren’t enough. For real impact, we must understand the difference between LCOE and System-LCOE and why this distinction matters for delivering reliable, low-emission power 24/7. 📉 LCOE. A valuable, but limited metric LCOE (Levelized Cost of Electricity) is a well-established measure of production cost per MWh over a plant’s lifetime. It’s an essential benchmark and the reason why solar, wind, and offshore wind are now increasingly preferred in many markets. However, LCOE only tells us what it costs to produce electricity, not what it takes to deliver it when and where it’s needed. That’s where System-LCOE becomes critical. 🧩 What System-LCOE adds to the conversation System-LCOE reflects the broader cost of integrating energy into a functioning power system. This includes: - Backup capacity (e.g., hydropower, gas peakers) - Storage (batteries, hydrogen, thermal, etc.) - Grid upgrades and interconnection - Curtailment losses and balancing services This doesn’t make renewables "too expensive", but reminds us that energy systems need more than generation alone. The Norwegian perspective: our flexibility is a strength Norway is in a unique position. A flexible hydropower system provides natural balancing for intermittent energy sources, such as wind. That makes it easier and cheaper to integrate renewables at scale, a goal many other countries are actively pursuing, for instance, through battery deployment or hydrogen-based storage. This means Norwegian companies, technologies, and experience in system integration and flexibility are more relevant than ever. ⚠️ Why this nuance matters Comparing LCOE from solar in Spain with baseload gas in Southeast Asia doesn’t tell the whole story. System integration matters, and System-LCOE can often be 1.5–3 times higher than LCOE, depending on geography, grid structure, and generation mix. Norwegian companies must be prepared to address this complexity when advising or exporting and show how smart design and flexible technology can manage these costs. ✅ Bottom line To support our partners in making sound energy decisions, we must: - Go beyond LCOE when discussing costs - Highlight Norway’s strength in system-level thinking - Recognise that renewables are essential, and so is integration 📣 Next time you see that solar or wind is “the cheapest,” ask: Is that just the generation cost or the full cost of reliable energy delivery, including the cost of infrastructure? Is that the full answer, or is it still blowin’ in the wind 👍

We’ve entered the biggest era of electricity demand growth since World War II. With 150 GW of new load expected in the next five years, we can’t afford to treat virtual power plants (VPPs) and distributed energy resources (DERs) as experimental. We need to position them as core infrastructure, on par with gas, wind, solar, and transmission. In my latest byline for Utility Dive, I write about the shift underway: utilities are no longer gatekeepers: they’re buyers. Programs like Xcel Energy’s Distributed Capacity Procurement and Exelon’s utility-scale battery filings show that when DERs are treated as capacity, not just flexible demand, utilities respond. This moment calls for alignment, not tribalism. It’s not about who owns the asset. It’s about who delivers reliable, scalable capacity. The companies building and operating DERs are solving real utility challenges, and they deserve a seat at the planning table. Let’s focus on outcomes, unlock scale, and build with urgency.

Some of us keep talking about DERs and better grid utilization to help solve the power demand problem. Excited to see things are starting to move in that direction. For years, when utilities needed to meet peak demand, the answer was almost automatic: build a gas peaker plant. That assumption is starting to crack. Not because of ideology—but because the math is changing. Take Consolidated Edison’s Brooklyn-Queens Demand Management program. Instead of building a new gas peaker and substation upgrade, they deployed a portfolio of distributed energy resources—efficiency, rooftop solar, and behind-the-meter batteries. It delivered the same reliability outcome at a fraction of the cost. Or look at what’s happening more broadly with virtual power plants—aggregations of home batteries, smart thermostats, EVs, and flexible loads. In places like California and Texas, these systems are now being treated as real capacity resources—able to shave peaks and reduce the need for fossil peakers. What’s emerging is not a one-off workaround. It’s a pattern. Distributed energy resources are increasingly taking over the role that gas peakers used to play: meeting short-duration spikes in demand, cheaply and quickly. And now there’s a new twist: Large loads—especially data centers—are beginning to join that stack. Through demand flexibility and workload shifting, they can act less like passive demand and more like dispatchable capacity. If this continues, the implications are significant: • Less need to build new gas peakers • Lower system costs (because DERs are modular and faster to deploy) • A grid that’s more flexible—and more participatory To be clear: DERs aren’t replacing all firm capacity. We still need solutions for multi-day reliability and extreme events. But they don’t have to. If DERs can cover even 10–20% of peak demand by 2030—as several analyses suggest—that’s enough to avoid a large share of new peaker builds. The “default” is shifting from one big plant solving the problem to a portfolio of smaller, smarter resources working together. That’s not just a technology story. It’s a different way of thinking about the grid. Keep watching this trend ….

For most of the last century, generators stabilised the grid as a by-product of producing energy. Today, we are building assets that stabilise the grid without producing energy at all. That shift identifies the binding constraint. Electricity system transition is no longer constrained by renewable resource availability. It is constrained by deliverability and operability. In inverter-dominated systems under rapid load growth, the binding constraints are: - transmission and major substation capacity - system strength, fault levels, frequency and voltage control - connection and commissioning throughput - secure operation under worst-day conditions - execution pace across networks and system services Generation capacity remains necessary. On its own, it no longer delivers firm supply or supports large new loads. Historically, synchronous generators supplied energy and stability together. Inertia, fault current, voltage support, and controllability were implicit. As synchronous plant retires, these services must be provided explicitly. Stability shifts from physics-led to control-led. System behaviour becomes more sensitive to modelling accuracy, protection coordination, control settings, and real-time visibility. Curtailment is not excess energy. It is a deliverability or security constraint. When transmission and substations lag generation, congestion and curtailment rise. Independent analysis shows that delay increases prices and emissions by extending reliance on higher-cost thermal generation. Distribution networks are no longer passive. They now host distributed generation, storage, EV charging, and large loads at the edge of transmission. Voltage control, protection coordination, hosting capacity, and connection throughput now constrain both decarbonisation and industrial growth. Firming is a hard requirement. Batteries provide fast frequency response and contingency arrest. They do not provide multi-day energy and do not replace networks or system strength in weak grids. Demand response reduces peaks. It cannot be relied upon for system-wide security under stress. Execution speed is critical. Slow delivery increases congestion duration, curtailment exposure, reserve requirements, and reliance on ageing plant. These effects flow directly into costs, emissions, and reliability. This is why electricity bills can rise even when average wholesale prices fall. Costs are driven by peak demand, contingencies, and security, not average energy. Large digital and industrial loads are transmission-scale, continuous, and failure-intolerant. They increase contingency size and correlation risk. At that scale, loads do not connect to the grid, they shape it. Supporting growth requires time-to-power, transmission and substation capacity in load corridors, explicit system strength and fault levels, operable firming under worst-day conditions, scalable connection and commissioning, and early procurement of long lead time HV equipment. #energy