Grid Resilience Solutions

For the last part of my Energy Resilience series, we have to talk about the worst-case scenario – when the lights actually go out. Earlier this year we saw that happen in Spain and Portugal. A major blackout left millions without power. Trains stopped, shops couldn’t take card payments, hospitals and factories switched to backup. A wake-up call that modern life depends on electricity in ways we often forget until it is gone.   This is what happens when grids are pushed to the edge by fast-moving disturbances or extreme conditions. A couple of years ago, South Australia experienced a state-wide blackout after severe weather took out multiple transmission lines. Investigations showed the system lacked enough inertia to stay stable through the shock. Part of the solution was to install synchronous condensers – giant flywheels that give the grid “weight” and stability. Siemens Energy delivered two of them as part of the response. Not the only measure of course – adapting regulation is also essential – but it showed something important: without resilience in the system, recovery is slow and uncertain. So what do we actually need if we want a fast ramp-up after a major incident? From my perspective, it comes down to three things. 1️⃣ Standardize before the crisis: When parts fail, every minute spent interpreting drawings or debating specifications is a minute the lights stay out. Standard equipment and uniform processes mean teams can move quickly because they are working with tools they already know. Recovery begins long before the fault happens. 2️⃣ Design power plants with failure in mind: A fast restart depends on assets built to recover quickly, not just run efficiently. That means black-start capability, smart redundancy where it matters and systems that can restart without waiting for the wider grid. In the U.S. for example we supported a power plant with a battery system that enables multiple restart attempts within one hour – resilience designed into the plant itself. 3️⃣ No improvisation in the dark: A blackout is the worst moment to negotiate who does what. Good restoration plans spell out which assets come back first, how to stabilize small sections of the grid and when to reconnect them safely. Regular drills with operators, authorities and major customers turn these plans into routine rather than theory. These steps matter because in any major incident skilled people are often the scarcest resource – grid operators, field crews and technical specialists. That is why preparation matters so much. Clear roles, common standards and trusted partnerships mean limited teams can do more in less time. Because when the worst happens what people remember is how long it stayed dark. I hope you have found this mini-series useful. I know social media is often about speed and short takes but sometimes – especially on important topics like this – I find it worthwhile digging into the detail together.✍️ I’d be interested to hear if you agree.

The Netherlands just unlocked 9GW of grid capacity without even building new lines. They’re using it to connect record levels of battery storage. 🇳🇱 Around a third of Dutch homes have rooftop solar, offshore wind will be the biggest source of energy by 2030, and the country has the highest penetration of EV chargers in Europe. It also has one of the most congested grids. While it is clear that our grids need to be modernised and expanded to integrate renewables, this can take years. Years that we don’t have, as new renewables, batteries, heat pumps are struggling to get connected. To better manage the grid, the Dutch TSO TenneT introduced “off-peak” flexible connection contracts. A user, such as a solar farm, would only have full access the grid 85% of the time. During peak periods for the grid, the TSO can partially or fully limit use. The TSO calculates that 9GW of capacity is available during off-peak hours, and is awarding 6GW to battery storage projects, which themselves can help better manage congestion further. The grid is not just about build, build, build, and the Netherlands shows it. We need countries to enact Rapid Capacity Plans, a toolbox of measures to unlock capacity today, while buying the time needed to expand the grid.

Alberta Just Told Data Centres: You’re Not Loads, You’re Grid Actors Alberta is drawing the line: data centres must act like generation if they want to connect. AESO’s draft Connection Requirements for Transmission-Connected Data Centres (TCDCs) rewrite what it means to be a ‘load. This isn’t just guidance. It’s the blueprint for binding rules. Core Rules for Data Centres: ➤ Ramping capped at 10 MW/min. AI clusters can ramp 100+ MW in seconds, but Alberta says: slow down. Compute must move at grid speed, not machine speed. ➤ Ride-through enforced. Ride through voltage sags below 45% of normal for 0.15 seconds, frequency swings as low as 57 Hz for nearly 5 minutes, and RoCoF up to 5 Hz/s. No disappearing acts. In practice: data centres must survive faults that would trip an industrial site because dropping hundreds of MW instantly is worse than riding through. ➤ Reactive power is mandatory. ±0.95 Power Factor with sub-second response. Loads must hold up voltages. ➤ Oscillations restricted. Net variability must stay below 16 kW per 100 ms and forced oscillations in the sub-synchronous band must stay under ±160 kW. Harmonics must be measured, reported, mitigated. Stability is not optional. ➤ Load shedding built in. Centres must trip portions of demand on command. And then come the quiet revolutions: • Backup power is emergency-only, no gensets tariff games. • ≥300 MW loads require dual SCADA paths; ≥500 MW must build physically diverse telecoms. Grid visibility is non-negotiable. • Every site must hand over EMT and phasor models, validated against real disturbance tests. Paper is dead; proof is alive. • Planning anchors are explicit: MSDC = 200 MW, Ramp30 = 300 MW/30 min. Why this matters: Alberta’s record peak demand is just 12.4 GW (Jan 2024), on a system with limited interties: one main 500 kV AC intertie to BC plus smaller AC links, including to Montana. Compare that to: • ERCOT, where summer peaks now push 90–100 GW • PJM, where summer peaks exceed 160 GW, with ~185 GW installed capacity Scale Matters: ▪ In ERCOT, the sudden trip of a 500 MW load is background noise. ▪ In Alberta, it’s a province-wide event, the equivalent of losing ~4% of system demand in an instant. That’s why AESO isn’t waiting for NERC’s 2026 guideline. It’s moving first. Each rule targets risks NERC already flagged: ramping, ride-through, SCADA, oscillations. This isn’t guesswork. It’s local action built on continental risk frameworks. This is Alberta drawing a line before hyperscale AI, crypto, and cloud reshape its grid. The real question is whether larger grids worldwide will act or wait until instability makes the choice for them. My view: This is the start of a new era. Programmable demand is no longer a silent passenger. It’s a grid actor, with obligations. 👉 The question is: will larger grids act before instability makes the choice for them? #DataCenters #AI #PowerSystems #GridStability #Policy #EnergyTransition #SystemStrength

With electricity demand surging, the U.S. transmission system is approaching its limits. Yet building new lines often takes 5 to 15 years due to permitting, environmental reviews, and land-use constraints. ⚡️Reconductoring offers a faster, lower-impact alternative. By upgrading existing lines with advanced conductors like ACCC or ACCR, utilities can double or even triple capacity—without building new towers or acquiring new rights-of-way. These high-temperature, low-sag (HTLS) conductors use materials such as carbon fiber to minimize sag and maximize throughput. 👉🏽 Why it matters: * Up to 3x current-carrying capacity using existing infrastructure. * Deployment in 18 to 36 months—far quicker than new construction. * 98% of U.S. transmission lines are viable for reconductoring. GridLab estimates reconductoring alone could provide over 80% of the additional transmission capacity needed to reach U.S. clean electricity goals by 2035. Yes, challenges like precision tensioning, splicing, and structural assessments remain, but they’re manageable with current tools, standards, and workforce skills. This is a proven, scalable solution that deserves greater attention. What’s your take? 👇🏽

🔴 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.

This week alone, we’ve replaced 4 transformers across different sites—each less than 5 years old. We’ve also rebuilt 2 switchboards that suffered flashovers, and we’ve already got the orders in to completely renew them. All of them were tied to solar sites. All of them were avoidable. Let’s stop pretending this isn’t happening. Too many of these substations were built as an afterthought—thrown in cheap to hit grid connection deadlines and satisfy investors chasing returns, not long-term reliability. We’re seeing: Switchgear that’s corroded beyond repair in under 60 months Inverters dumping harmonics back onto the network with no mitigation Poorly specced protection schemes that offer no selectivity or grading Transformers undersized, under-ventilated, and overstressed from day one No provision for future battery integration or reactive power compensation This isn’t about bad luck. It’s about bad design. And it’s happening across the country. Some of these sites will never make it to year 10 without major intervention. Many will fail long before their PPA matures. And every time it’s the same story: “we didn’t think it needed to be that robust,” “we had a tight budget,” “we assumed it would last.” You don’t build a resilient energy future with assumptions. At Johnson & Phillips, we’ve built our reputation on fixing what others cut corners on. But make no mistake—our goal isn’t just to repair. It’s to raise the standard. Power distribution infrastructure matters. Substations are not just connection points—they’re the backbone of performance, safety, and scalability. If you build them like an afterthought, they will fail. And they are failing. This isn’t a warning. It’s already happening. If you’re operating, investing in, or building solar and storage sites—make your substation a priority. The quality of your entire system depends on it.

Grid bottlenecks are a feature — not a bug — of the energy transition. For years, we viewed economics as the main hurdle to scaling clean energy. High costs for wind, solar, heat pumps, and storage dominated the conversation. But the world has changed. Thanks to extraordinary innovation and dramatic cost reductions in renewables and electrification technologies, the bottlenecks we face today are different. They’re no longer about whether clean energy is affordable — it is. Instead, the challenge is whether our energy systems can evolve quickly enough to integrate it. A recent Financial Times piece highlights this clearly: across Europe, the rapid build-out of renewable generation now outpaces the ability of grids to move electricity to where it’s needed. Curtailment, congestion, and long queues for grid connections already cost billions annually — and without decisive action, these costs will grow. This isn’t a sign of failure. It’s a sign of success. It means the transition is happening faster than the infrastructure built for the fossil era can handle. The rise of decentralised, variable renewables and electrified heating and transport requires a fundamentally different approach to planning — one that anticipates growth rather than reacts to it. The EU’s move toward more coordinated, top-down scenario building and cross-border grid planning recognises exactly this. Better alignment between countries and system operators, faster permitting, and prioritisation of critical projects are essential steps to unlock the full value of cheap clean energy. Because every euro lost to bottlenecks is not a cost of climate action — it’s a cost of not modernising our grids fast enough. The more successful we are in deploying renewables and electrification, the more urgently we must upgrade and expand our grids. Grid constraints are not a reason to slow down. They’re a reason to speed up the transformation of an energy system that was never designed for the technologies now powering our transition.

America's power grid has lots of capacity waiting to be unlocked. We need to build more transmission, but we also need to unlock all of the unused capacity from the transmission we have already built. Duke researchers found that the grid operates at just 53% of its capacity across regional systems. Meanwhile, utilities are raising rates faster than inflation, and grid congestion is costing ratepayers billions every year. Dynamic Line Ratings (DLR) could change that. The technology is proven, deployed globally, and ready to scale. National Grid in the UK is using it across 275 km of overhead line, saving consumers an estimated £20 million per year — with capacity gains that actually increase when offshore wind is producing most. That's not a pilot. That's a system-level transformation. So why aren't US utilities moving faster? The honest answer: incentives. Utilities earn returns on capital investment. New poles, new wires, new transformers go into the rate base and generate guaranteed returns. DLR can cost 95% less than reconductoring a line — which is great for ratepayers, but means a much smaller return for the utility. The regulatory environment shapes the decision, every time. PPL Electric deployed DLR instead of reconductoring and saw a 10–30% capacity increase, in less than half the time, with zero line outages, and an estimated $64 million in congestion savings. The economics work. The regulatory architecture doesn't — yet. Virginia just passed a first-of-its-kind grid utilization bill. It's a start. But FERC and state regulators need to build the incentive structures that make DLR deployment the rational choice for investor-owned utilities. The technology is ready. The policy just has to catch up. I sat down with Vishal Kapadia of LineVision who has transformed their product line into something that Utilities are finding much more appealing.

Study: Generators May Provide a Faster Path to Power A new study by energy researchers suggests that data centers could get faster access to power by adopting load flexibility, agreeing to briefly curtail utility usage and shift to generator power. In an in-depth analysis of the U.S. power grid, researchers at Duke University estimate that this approach could tap existing headroom in the system to more quickly integrate at least 76 gigawatts of new loads, arguing that even a small reduction in peak demand could reduce the need for new investments in transmission and generation capacity - as well as the need to pass on those investments to ratepayers. Data centers are all about uptime, and thus have been resistant to innovations that create additional risk around reliability. But current power constraints in key markets, along with growing demand for AI training workloads (which may be more interruptible than cloud or colocation) has prompted the industry to explore load flexibility options. Last year the Electric Power Research Institute (EPRI) launched the DCFlex project to work with utilities and a number of data center operators - including Compass Datacenters, QTS Data Centers, Google and Meta - on pilot projects for load flexibility. The Duke study, titled "Rethinking Load Growth," puts some interesting numbers on the upside potential. Their findings: - 76 gigawatts of new load could be enabled by a annual load curtailment rate of 0.25% of maximum uptime, equivalent to 1.7 hours per year operating on backup generators. - An annual curtailment rate of 0.5% (2.1 hours annually) could enable 98 GWs of new load, while a rate of 1.0% (2.5 hours) could boost that to 126 GWs. - A 0.5% curtailment could enable 18GWs in the PJM and 10 GWs in ERCOT, the research finds. At least one hyperscaler seems open to the idea. “This is a promising tool for managing large new energy loads without adding new generating capacity and should be part of every conversation about load growth,” said Michael Terrell, Senior Director of Clean Energy and Carbon Reduction at Google, in a LinkedIn post. With the acceleration of the AI arms race, speed-to-market is now a top priority, along with a competitive opportunity cost for companies that are unable to deploy new capacity. There are tradeoffs to consider (including more emissions), but the Duke paper will likely advance the conversation. Duke study: https://lnkd.in/eS3s_pvk Background on DCFlex: https://lnkd.in/euK746Zy