A year ago the data centre conversation was about scale. Increasingly it is about what happens when the announcements meet the physical grid. New capacity is being announced at roughly 435 megawatts a month, enough to power a city of 400,000 people, but two-thirds of that committed load tends to disappear the moment utilities ask for a financial commitment behind it. AI training facilities create load profiles that drop 30% in five minutes, or 190 megawatts in three. The grid's mechanical inertia is retiring just as hyperscaler ambition accelerates, and regulation is lagging on both sides of the meter.

In this episode, interim host Bridget van Dorsten returns the microphone to host Sylvia Leyva Martinez. The two recap six months of the show through clips from Chris Seiple (Wood Mackenzie), Tom Falcone (Large Public Power Council), Akhil Batheja (Bloom Energy), Kay Aikin (Dynamic Grid), Kristina Carlquist and Christian Payerl (ABB), Shannon Miller (Mainspring Energy) and Nick Chaset (Octopus US), and map out the questions that will shape Sylvia's return.

The central tension of the past six months: announcements are racing ahead, but utilities, regulators and the physical grid cannot move at hyperscaler speed. A data centre can be built in two years. New generation takes five to ten. That mismatch is why developers have stopped waiting on the grid: 35% of US data centre project capacity announced in 2025 was planned with around-the-meter generation, and 92% of bridge prime power deals are now struck before the end tenant is signed, inverting the usual logic of infrastructure development. But collocated power is still, in Bridget's framing, a science project. The load behaviour demands a coordinated portfolio: supercapacitors and UPS catching millisecond swings, synchronous condensers supplying inertia, fuel cells and linear generators offering modular, fuel-flexible bridging power as a hedge against demand risk. Nick Chaset's intervention cuts the other way: the UK already hosts the world's largest residential virtual power plant, and the cheapest megawatt is the one you don't build. The episode closes on duelling forward views, Tom Falcone's cooperative optimism against Kay Aikin's affordability death spiral, with the question of who ultimately holds the bag if the announcements don't materialise still unresolved.

Sylvia sets out what she wants to explore next: the regulatory contradiction where utilities support bring-your-own-generation but cannot guarantee protection from curtailment; renewables supply constraints and the transformer and labour bottlenecks that affect every fuel source equally; the return of energy security as a framing now that "energy transition" has fallen out of political favour in the US; and the community opposition data centre developers are only beginning to grapple with.

Here is the latest Horizon's piece that Bridget referenced:

https://www.woodmac.com/horizons/can-us-data-centre-development-outpace-grid-development/

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The energy transition conversation focuses on what connects to the grid. Far less attention goes to whether anyone is coordinating what those assets do once connected. AI training runs swing hundreds of megawatts in seconds as GPUs checkpoint and restart a profile that looks like a generator tripping offline. At distribution level, millions of inverter-based resources create localised variability that overwhelms individual circuits even when aggregate models look healthy. The planning tools in use today were designed for neither problem.

Host Bridget van Dorsten is joined by Kay Aikin, CEO and Founder of Dynamic Grid, energy engineer, grid architecture advisor to the DOE-supported GridWise Architecture Council, and contributor to the UN Environmental Program's building decarbonisation work. Kay unpacks what an AI training facility actually does to the grid with full GPU load for hours or days, then a drop to ten percent in seconds during checkpointing. She talks about how at the scale now planned, the Stargate project in Texas alone could represent ten percent of ERCOT disappearing in four seconds. The behaviour is stochastic and cannot be modelled with traditional statistical tools. At distribution level, virtual power plants responding to wholesale signals without circuit-level visibility can create competing oscillations, the kind of emergent dynamics that contributed to the Spanish grid failure.

The proposed fix is an AI controller at the substation, sending price-based signals and flexible operating envelopes to large assets and VPP operators, giving them twenty-four-hour forecasts and real-time circuit visibility. Total cost: under a hundred thousand dollars installed. The reason it isn't everywhere is cost-of-service regulation. Utilities earn returns on deployed capital, so a million-dollar transformer replacement is more profitable than software that eliminates the need for it.

Without new approaches, rebuilding the US distribution grid could cost up to ten trillion dollars by 2040. Kay is developing grid utilisation metrics with regulators in Maine, Virginia, and Maryland to incentivise extracting more from existing infrastructure. The episode closes on the need for distribution system operators and the affordability death spiral that looms if the structural incentives don't shift.

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As coal and gas plants retire, the energy transition conversation focuses on replacing their generation capacity. What gets far less attention is the loss of the physical properties those machines provided for free: inertia that stabilises frequency, fault current that supports voltage during disturbances, and reactive power that regulates voltage across the network. These services come from the physics of enormous spinning rotors synchronised to the grid, responding instantaneously, without sensors, software or control loops. As inverter-based resources replace them, that mechanical immune system disappears, and a new, extreme stress test is arriving at the same time in the form of AI data centres whose loads can swing by hundreds of megawatts in a fraction of a second.

Host Bridget van Dorsten is joined by Kristina Carlquist, General Manager of Synchronous Condensers at ABB, and Christian Payerl, Sales Manager of Synchronous Condensers at ABB, to unpack why a technology that has existed for as long as the grid itself is now experiencing a revival.

Christian explains the three ancillary services the grid is losing, inertia, short-circuit current and reactive power, and why inverter-based generation does not replace them. Grid-forming batteries can be programmed to simulate inertia, but each charge-discharge cycle degrades lifetime, overload capacity is limited to microseconds, and the models needed for accurate grid simulation are often tied up in manufacturer IP. Synchronous condensers respond on physics alone, in both directions, with no degradation and no modelling uncertainty. The recent blackout in Spain illustrates what happens when that gap is left unfilled.

Kristina walks through the commercial traction. ABB's partnership with VoltaGrid on isolated data center microgrids has grown from an unexpected inbound enquiry in late 2024 to dozens of synchronous condensers delivered. On the grid-connected side, the Faroe Islands have deployed four units with a fifth on the way as part of their push toward 100% renewables, already achieving multi-day periods of fully renewable operation. ABB is also working with Korea's Jeju Island on its first flywheel-equipped deployment. The demand pattern is widening: islands integrating renewables, TSOs managing weak grid regions, mines electrifying operations, and now data centre developers who had never considered grid stability equipment before.

The episode closes on regulation and standards. Christian, who participates in international standards work through CIGRE, notes that there is still no international standard for flywheel safety and that the treatment of inertia as a paid service varies dramatically by country. While inertia is compensated as a paid service in the UK, in Sweden it is treated as free – rotating machines providing it receive no income stream for doing so. As data center load grows faster than regulation can respond, both guests argue that the answer is not one technology but a combination, provided the industry, utilities and policymakers can align on what the grid actually needs to remain stable.

This episode is sponsored by GridBeyond.

Energy asset owners face a critical challenge: how to optimize performance and drive new revenue in competitive, fast-moving markets. GridBeyond solves this through AI-powered forecasting, energy trading and optimization. 

GridBeyond's platform delivers: 

• Precision forecasting to anticipate market opportunities 
• Intelligent market access across multiple revenue streams 
• Real-time control that responds instantly to market conditions 
• Optimization that combines AI insights with expert oversight 

Whether you're managing batteries, gas peakers, hybrid sites, or complex multi-asset portfolios, GridBeyond helps you turn assets into high-performance revenue machines. The proven platform has helped businesses across the energy sector maximize returns and accelerate their energy transition. 

Want to learn more? Visit go.gridbeyond.com/recharged  https://go.gridbeyond.com/recharged  

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Utilities are under pressure to deliver generation that is dispatchable, affordable, and clean enough to satisfy increasingly stringent environmental rules, notoriously hard to do in one asset. As renewables grow, the gas turbines and engines that have historically filled the gap come with a NOx problem, a CO2 problem, or both. Hydrogen offers a path through, but the supply isn't there yet. So what do you build today?

Host Bridget van Dorsten is joined by Shannon Miller, CEO of Mainspring Energy, and Will Hazelip of National Grid Ventures, to dig into a technology most listeners haven't heard of and the first commercial hydrogen-powered deployment of it. Mainspring's 250-kilowatt linear generator is being installed at National Grid's 1,500 MW North Port facility on Long Island, in partnership with NYSERDA, the Long Island Power Authority, and Stony Brook University.

Shannon explains how Mainspring redesigned the generator using the power electronics that drive solar inverters, batteries and EVs, replacing mechanical systems with software, eliminating the flame, and operating at temperatures low enough to take NOx out of the equation. An adaptive pressure cycle, software-controlled in real time, runs the same hardware on hydrogen, compressed natural gas, biogas, propane or blends, with no hardware change. The 250 kW form factor matters too: efficiency holds across the full load range, fleet redundancy replaces single-asset reliability risk, and deployment is a concrete pad plus electrical and fuel hookups rather than a multi-year build.

Will frames the project against the regulatory backdrop. Long Island sits in a non-attainment zone for NOx, and New York's path to a carbon-free grid requires what the state calls a dispatchable emissions-free resource. The unit will run for 12 months on green hydrogen and on compressed natural gas, with Stony Brook measuring emissions and efficiency, NYSERDA watching for regulatory design, and National Grid building operational experience for the rest of its ageing fleet.

The economic case rests on the alternative. New-build hydrogen-capable gas turbines run $3,500–$4,000/kW on capex (per Wood Mackenzie), with delivered power costs reaching $300–$900/MWh once hydrogen is layered in. Shannon's point is that committing to a single-fuel turbine only pays off if the fuel actually arrives at the scale and price you assumed. With hydrogen supply uncertain, that's a stranded-asset risk linear generators avoid by running on whatever fuel is available today. Will adds the carbon-market angle saying that as carbon pricing develops, real-time fuel switching becomes an optimisation lever, not just a hedge.

Then there’s the supply reality. Total US hydrogen production today isn't enough to fuel a single 500 MW power plant, and with 45V tax credit requirements tightening and federal climate policy in flux, the gap between hydrogen ambition and supply isn't closing fast. Will's suggests starting with the fuels that exist today and scale into hydrogen as supply grows.

The episode closes on demand. Mainspring's factory produces 325 MW a year today and can roughly double in 12–15 months, with pull from industrial customers, data centres and AI infrastructure, and utilities at once, driven by the same problem: nobody can get power fast enough.

This episode is sponsored by GridBeyond.

Energy asset owners face a critical challenge: how to optimize performance and drive new revenue in competitive, fast-moving markets. GridBeyond solves this through AI-powered forecasting, energy trading and optimization. 

GridBeyond's platform delivers: 

• Precision forecasting to anticipate market opportunities 
• Intelligent market access across multiple revenue streams 
• Real-time control that responds instantly to market conditions 
• Optimization that combines AI insights with expert oversight 

Whether you're managing batteries, gas peakers, hybrid sites, or complex multi-asset portfolios, GridBeyond helps you turn assets into high-performance revenue machines. The proven platform has helped businesses across the energy sector maximize returns and accelerate their energy transition. 

Want to learn more? Visit go.gridbeyond.com/recharged  https://go.gridbeyond.com/recharged  

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Empty gigawatt factories, product recalls, participation rates that never materialised, and a policy environment that has now stripped the green premium entirely. The electrolyzer industry has had a brutal few years and most of the companies that raised hundreds of millions on the back of the hydrogen hype cycle are now sitting with fixed costs they cannot sustain and field deployments they are not proud of. 

Host Bridget van Dorsten speaks with Raveel Afzaal, CEO of Next Hydrogen, one of the few electrolyzer manufacturers that chose to watch from the sidelines while competitors scaled into the storm. Raveel describes the decision in blunt terms: in 2021, when cost of capital went to near zero and capital discipline evaporated, Next Hydrogen looked at the macro signals; rising inflation, rising interest rates, a market telling them their Hyundai partnership was worth a 5% share price drop, and chose to extend their runway from 18 months to five years. That meant hard capital allocation decisions, and the answer was to invest in the product, not the factory. 

 The conversation goes deep into a problem that rarely gets discussed publicly: the commercialisation valley of death. Getting to a working prototype is celebrated, but the productisation phase, technology readiness levels five through seven, is where the funding gap is most severe and the cost shock is greatest. Costs typically rise three to five times from prototype stage, revenues do not yet exist, and neither government programmes nor conventional investors are structured to bridge it. Raveel explains why so many companies that made it to prototype stage never made it to commercial deployment and what surviving that valley actually required. 

 Raveel also pushes back on a common framing around Chinese versus Western electrolyzers. His argument is that the quality question is not a national origin question , it is a materials question. What membranes, what bipolar plates, what catalyst, what functional safety architecture? Next Hydrogen's own answer to those questions is unusual: replacing nickel bipolar plates with large injection-moulded specialty engineered plastics, eliminating corrosion risk entirely and reducing cost through higher material utilisation rather than lower-grade materials. The company holds 40 patents on a cell architecture designed from the outset for direct connection to variable renewables, a design decision made in 2008, when the rest of the industry was still building for baseload. 

 The episode closes on what the next two to three years look like for electrolyzer manufacturers. Raveel's view is that consolidation is coming, but many companies won't survive long enough to be part of it, their fixed costs are too high and their runway too short. The companies that survive will be those with variable cost models, disciplined project selection, and a genuine answer to three questions: Can you access excess electrons? Can you deliver containerised, plug-and-play solutions that control total installed cost? Can you reliably handle the intermittent operations that direct renewable connection demands? Next Hydrogen is betting the answer starts with getting the cell design right first. 

Today's episode is sponsored by GridBeyond.

Energy asset owners face a critical challenge: how to optimize performance and drive new revenue in competitive, fast-moving markets. GridBeyond solves this through AI-powered forecasting, energy trading and optimization. 

GridBeyond's platform delivers: 

• Precision forecasting to anticipate market opportunities 
• Intelligent market access across multiple revenue streams 
• Real-time control that responds instantly to market conditions 
• Optimization that combines AI insights with expert oversight 

Whether you're managing batteries, gas peakers, hybrid sites, or complex multi-asset portfolios, GridBeyond helps you turn assets into high-performance revenue machines. The proven platform has helped businesses across the energy sector maximize returns and accelerate their energy transition. 

Want to learn more? Visit go.gridbeyond.com/recharged  https://go.gridbeyond.com/recharged  

See Privacy Policy at https://art19.com/privacy and California Privacy Notice at https://art19.com/privacy#do-not-sell-my-info.

Millions of enrolled devices, 60 utilities, and the participation rate gap that's been embarrassing the US market for a decade.

 US residential virtual power plants have been a promising idea that's consistently underdelivered — participation rates below 5%, fragmented apps, siloed programmes, and utilities that have simply never had to compete for a customer's attention. Meanwhile, Octopus Energy has built the world's largest residential VPP in the UK, with EV driver participation rates of 50 to 70%. The question has always been whether that model can travel to a market where most customers have no supplier choice at all.

 Bridget van Dorsten speaks with Nick Chaset, CEO of Octopus Energy US, about the acquisition that represents Octopus's biggest bet on answering that question: a majority stake in Uplight alongside Schneider Electric, giving Octopus access to established relationships with more than 60 US utilities — including eight of the ten largest.

 Nick argues the participation gap isn't really a cultural problem or a technology problem. It's a regulatory design problem. US flexibility programmes have been built device by device, forcing consumers to juggle multiple apps and enrolments — and in some cases prohibiting them from combining assets across programmes. Octopus's answer is one app, a 30-second sign-up, and a value proposition framed entirely around what consumers actually care about: lower bills. Can that translate through a utility partnership channel rather than a direct retail relationship?

The conversation also tackles the data centre dimension. Nick makes the case that residential flexibility isn't a separate story from the large load interconnection challenge — it's part of the solution. If utilities can statistically guarantee load reductions from tens of thousands of enrolled homes during peak hours, they may be able to connect larger data centre loads at smaller interconnection points. And in many hours when a data centre might otherwise ramp down, it could simply be cheaper to pay consumers to flex instead.

 Octopus's model is built on trust earned through direct consumer relationships. Can that translate through a utility intermediary at scale, across 60 different utility cultures without losing what makes it work?

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Why nuclear has never been project financed and how that might finally be about to change.

Every nuclear plant ever built has ultimately been backstopped by taxpayers or ratepayers. Not because the technology doesn't work, but because nobody has ever cracked the construction cost and schedule problem well enough to convince a bank to finance it without government support. Bridget van Dorsten is joined by Jake Jurewicz, Co-founder and CEO of Blue Energy, to explore why that has been so hard and what a credible path to fixing it might actually look like.

Jake walks through the root cause of nuclear's cost overrun problem and it is not the reactor. The reactor equipment itself represents around 7% of total project costs. The real problem is what Jake calls nuclear construction overhead: the cost of mobilizing, training, and retaining the 10,000 or so skilled workers needed to build these plants in the field, the way we have been building them for 70 years, essentially the same way you would build a castle.

The episode then turns to what Blue Energy is doing differently. By intentionally selecting sites accessible by barge and contracting existing oil and gas fabrication yards and shipyards to build large pre-assembled modules offsite, Blue Energy aims to bring fixed-price contracts into nuclear for the first time, the same contracting structure that made offshore wind and LNG bankable. Jake explains why that single shift changes everything for project financing.

Bridget and Jake also work through the demand side of the equation: why hyperscalers are becoming the crucial beachhead market for new nuclear, what binding PPAs from investment-grade counterparties actually signal versus announcements, and why the restarts and uprates, while valuable, only go so far.

The conversation also covers Blue Energy's first announced project at the Port of Victoria in Texas, a 1.5 gigawatt nuclear-powered AI data centre co-located with a gas-to-nuclear conversion, designed to accelerate commercial operation and reduce cost of capital even without government loan support. Jake explains the mechanics of why firing the balance of plant with gas first before switching to nuclear steam is not a compromise but a genuine financing innovation.

Finally, Jake offers a view of what signals actually matter when separating the nuclear renaissance from the noise: binding PPAs, large balance sheets standing behind fixed-price contracts, and projects moving through the Nuclear Regulatory Commission rather than staying at the prototype stage.

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What two decades of flat demand means for a grid now expected to double in size

The US went from essentially zero load growth for twenty years to 3% national growth almost overnight. The supply chains, permitting pipelines, engineering workforce and regulatory processes were all calibrated for a different world. Bridget van Dorsten is joined by Tom Falcone, President of the Large Public Power Council, representing the 30 largest publicly owned utilities in the United States, collectively owning around 85% of public power assets and currently serving roughly 18% of all US data centre load.

Tom explains what makes public power structurally different from investor-owned utilities: locally governed, not-for-profit, and built to minimise cost rather than earn a return on equity. That governance model turns out to matter a great deal when trillion-dollar hyperscalers come looking for power. Public power utilities have no financial incentive to favour their own assets over a customer's, and their local accountability makes deal-making faster and more direct.

Bridget and Tom also work through the mechanics of how the industry is actually responding. Large-load tariffs are reshaping the interconnection queue, forcing hyperscalers to make long-term financial commitments rather than reserving capacity for free. About two thirds of speculative requests disappear once real commitments are required, which tells you something about the gap between announced demand and real demand. LPPC members are nonetheless planning to add around 60GW of new generation over the next ten years to meet load that is forecast to grow from 4GW to 18GW of data centres in their territories alone, in just five years.

The episode also tackles private use rules, a Treasury regulation from 25 years ago that nobody expected to become a bottleneck for the AI era, the capacity factor realities that make peak-day power so much harder to deliver than annual energy, the nuclear question and why federal involvement is probably unavoidable if the US wants to build at scale, and where CCS can and cannot realistically be deployed.

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Carbon capture and storage has long been framed as a clean technology that’s forever five years away. Bridget van Dorsten speaks with Tim Vail, CEO of ION Clean Energy, to explore why a surge in AI data-centre demand is reshaping the market for decarbonised gas – and how viable a solution it really is.

Tim argues we’ve entered a buyer-led era for carbon capture, driven by hyperscalers like Amazon, Google and Microsoft who need 24/7 power fast - but are still committed to climate and decarbonization goals. That creates a new question for the energy transition: can natural gas + CCS deliver competitive renewable energy-level carbon intensity, while supporting grid resilience and scaling quickly enough for near-term energy projects?

A big part of the conversation is about measurement and credibility. Tim explains how “carbon intensity” has to be assessed across the full value chain - from wellhead to electrons - including methane leakage. The rise of methane monitoring (ground, aircraft and satellite) and verification systems are helping utilities and buyers prove emissions performance, which is increasingly essential for energy finance, green finance, and corporate reporting. How does it work?

 Plus, Tim and Bridget debate the economics. Hyperscalers don’t buy “dollars per ton of CO₂ captured” - they buy power. Tim breaks down what CCS can add on a $/MWh basis, how incentives like the US 45Q tax credit can influence the cost, and why execution (getting projects financed and to final investment decision) is now the real bottleneck. Along the way, Bridget and Tim place CCS in the broader clean firm competition set, including nuclear, hydrogen, geothermal, and solar energy plus batteries, and what this means for future energy predictions and energy policy.

The big question: is CCS at last moving from concept to commercial scale - not because the chemistry suddenly changed, but because demand, verification, and project finance finally might be aligning? 

About Interchange Recharged

Interchange Recharged is the Wood Mackenzie podcast exploring the technologies, markets and energy policy decisions shaping the future of energy - from clean tech and clean technology to infrastructure, grid resilience, and the financing models behind the next wave of decarbonisation.

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After more than a decade of flat demand, the US power sector is now facing explosive growth, arriving faster than grids, generation, and transmission can be built. In this episode, Interim host of Interchange Recharged Bridget van Dorsten is joined by Chris Seiple, Vice Chairman of Power & Renewables at Wood Mackenzie, to unpack one of the defining challenges facing the modern energy system: how utilities, developers, and policymakers are responding to an unprecedented surge in electricity demand driven by data centres, AI, and reshoring manufacturing. 

Bridget and Chris explore what makes this moment different, why planning cycles are colliding with short technology investment horizons, and how this mismatch is forcing a fundamental rethink of how the power business works, from energy policy to energy finance. The main point is that the difference between regulated and deregulated markets is widening, as vertically integrated utilities strengthen their advantage in managing large loads.

New mechanisms like large-load tariffs are reshaping rate design, investment risk, and affordability - Chris explains how. Plus, deregulated markets may be approaching a tipping point, as traditional price signals struggle to accommodate demand arriving at this scale and speed. What does it all mean for energy?

Crucially, the episode looks beyond the immediate crunch to the longer-term implications for the energy transition. From renewable energy and solar energy pipelines to grid resilience, transmission innovation, and behind-the-meter solutions, this demand boom could become a powerful catalyst for clean tech, clean technology, and energy innovation, even as subsidy regimes change and capital costs rise.

The discussion also touches on the role of hydrogen, nuclear, and emerging grid technologies in supporting future energy projects, and why this period of rapid load growth may ultimately accelerate decarbonisation rather than slow it. If you’re tracking climate policy, climate change, green finance, and long-term energy predictions, this episode is for you; hear why today’s data centre boom could shape the next several decades of the power system.

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