EP.270 Review of 2025: Insights from the Global Energy Transition with 12 Aurora Experts

This April Aurora Energy Researches Flagship Spring Forum returns to London for its 12th year. On 29th April 2026, join over 450 senior energy leaders for a full day of insight, debate and high-level networking. Here's CEO Keynotes from Global Energy and Finance Leaders, explored geopolitics, system resilience and investment strategy, and experienced live debates, breakout sessions and a recording of Aurora's Energy Unplugged podcast. As the energy transition enters a decisive phase, be part of the conversation shaping what comes next. Head to auroraer.com/events to book your pass and use the code podcast20 that podcast20 for an exclusive 20% discount. Welcome to Energy Unplugged, to go to podcast focusing on the global energy transition. I'm Richard Howard, the Global Research Director at Aurora Energy Research. This episode of the podcast is an end-of-year special edition which we're calling energy unwrapped. We've thought we would unwrap the year with a look back at some of the key themes which have shaped the global energy transition in what has been a pretty tumultuous year. As some have recently said to me, every year since 2020 has felt like a once-in-a-lifetime event and 2025 certainly was no exception. We've seen geopolitical upheaval, technological leaps and climate extremes which have all combined to stress test the energy transition like we've never seen before. In this special edition podcast, we'll take you through four key themes which have shaped the energy sector and energy transition this year. Firstly, US policy shocks under President Trump and their ripple effects across global energy markets. What happens as the US doubles down on America first and goes into reverse on its climate commitments? Secondly, we'll look at the AI and data center boom, a mega trend which has shaped electricity demand and investment strategies. The total power demand from data centers is now equivalent to that of a major economy such as Germany. The utilities and grid operators, this is both the biggest growth opportunity in decades and also the toughest test to scale as fast as the tech industry. Thirdly, we'll look at the reliability challenge as grids worldwide grapple with more renewables, increased weather volatility and aging infrastructure. The stakes are high, 60 million people lost power in the Iberian blackout in the spring. I want to explore how global markets are rethinking resilience and building the grids of the future before the next crisis hits. Lastly, we'll look at the race to integrate renewables across global power markets. We've now hit the amazing milestone of five terawatts of installed renewables capacity worldwide. But at the same time, we set new records for the number of negative price periods and grid catailment. What are the innovations in technology business model and market design which are critical to making renewables integration a success? These are the forces shaping the energy transition. Though if you want to understand where we're headed, let's look at the events of 2025 in more detail. For the podcast, I'll be drawing on Aurora's extensive research and analysis as well as a host of experts. I've invited not one or two but a total of 12 individual contributors from across Aurora's global team. Each of them bringing insights on particular topics or markets and this all comes together in this jam packed episode. For listeners who subscribe to Aurora's services, you'll also find a report publication in our EOS platform which pulls together a few key slides on each of the topics covered. It's an amazing summary and if you want to dive even deeper, then we provide links to longer reports. Okay, let's start with our first theme. This is on the macro geopolitical issues and how U.S. policy choices are shaping domestic and global energy markets. Since President Trump's inauguration into office in January, we've seen a blitz of policy changes and unprecedented pace of executive action with a total of 142 executive orders made just in his first 100 days. Many of these have had far-reaching effects on geopolitics, the economy and energy markets, both in the U.S. domestically and also far beyond its borders. In particular, it's worth highlighting a few things. Trump's America first approached to trade with sweeping tariffs and retaliatory measures. Then the significant focus on security, both in the U.S. securing its own borders and in pushing for peace in Ukraine and the Middle East. And also in the energy sphere, a renewed pursuit of U.S. energy dominance and independence combined with climate skepticism and a rowing back of green policies from the Biden era. I want to unpack these trends and see how they've shaped the energy sector and energy transition, not just in the U.S. but also around the world. The first guest I want to bring into the podcast is Victor Del Carpio, senior associate in Aurora's global commodity team, who at the start of 2025 wrote an Aurora Insight report on the topic of Trump's tariffs, in which we modeled various different scenarios. At the time of writing this report in early 2025, it was quite unclear which way we would be going on tariffs, as President Trump had threatened some very high tariff levels, especially towards China, which had also threatened retaliation. And it took some months before the final outcomes became clear. Welcome to the podcast, Victor. Could you give a bit more context on the U.S. tariffs? When you wrote the Insight report, what was the full spectrum of scenarios that had been envisaged? And what would the impact have been of the highest tariff scenarios envisaged at the time in terms of impacts on the global economy and the energy sector? Thank you, Richard. The U.S. has four major trade partners, the European Union, Canada, Mexico, and China. Together with the account, we're up to 60% of U.S. trade, which includes energy, chemicals, food, and electronics, among other goods. So it came a bit as a surprise when the Trump administration adopted an aggressive policy target in these countries. Continuous retaliation escalated the trade war between major economies, particularly between the U.S. and China. But it also extended globally, eventually affecting nearly all countries to some degree. We modeled three scenarios to address market uncertainty. First, full-blown tariffs. Here negotiations completely failed. This result in an all-out trade war with every country retaliating against the United States. Second, U.S.-China focused trade war. In this case, this forms an alliance with the rest of the countries, but acts aggressively against China, imposing tariffs primarily on Chinese goods, while other countries received some reprieve. Third, minimal tariffs. A scenario where tariffs are lowered across the board. Negotiations succeed, all countries come to the table, and agreements are reached for reduced tariffs. In all the scenarios, services were exempt, and energy was also exempt, except for Canada and China. Now, in this scenario with full-blown tariffs to summarize the impact on the economy, Mexico's GDP growth slows the most by around 3% by 2030. China, meanwhile, mitigates the impact of tariffs by redirecting some goods to other regions, for example, the EU. The EU, by contrast benefits slightly as cheaper Chinese goods flow into its markets. For the U.S., GDP growth slows by approximately 1.7% by 2030, amounting to a loss of $400 billion. In the case of the impact on prices, the gas and flows, for Mexico and Canada, Mexico's pipeline imports the client due to slower GDP growth and reduced gas demand. Canada, facing a 10% tariff, gets pipeline exports to the U.S. and also as lower U.S. demand takes hold, they go down. In the United States, the reduction in pipeline imports from Canada is offset by lower pipeline exports to Mexico and increase domestic production. U.S. LNG exports decreases due to Chinese retaliatory tariffs, but haircut prices remain stable as there is no material change in domestic gas production. For the rest of the world, Chinese cut off from U.S. LNG exports and needs to soar supply from other countries. Japan and South Korea absorb most of the targeted U.S. cargoes. The EU also receives more U.S. LNG in the European range market year for business table. Could you bring us up to date on what has happened since? Where did the tariffs land at the end and what impacts everything across the global economy and energy sector? Since the modeling, the most extreme tariffs were partially implemented but later scaled back. The U.S. maintained a 10% baseline tariff with most Chinese goods, with some strategic sectors like semiconductors and EVs facing higher rates. The EU, Canada, and Mexico negotiated exemptions of water-based arrangements is in tensions. According to the Peterson Institute for International Economics, these studies have acted as a persistent drag on growth. USGDP is estimated to be around 0.51% lower than it would have been without the trade war, with consumers bearing most of the cost through higher prices. Trade flows have shifted with China diversifying exports and the U.S. increasing imports from Saudis, Asia, and Mexico. In energy, the impact has been mixed. USLNG exports to China decline due to their territorial tariff, but volumes were redirected to Europe and other Asia markets. Oil and gas prices shocked and made weaker global demand, while clean energy sectors face higher input costs due to tariffs on solar components and metals, slowing deployment in some regions. Many thanks Victor for coming on the podcast has been fascinating. I'd like to move us on to our next topic, which is again US-centric with global repercussions. As I mentioned earlier, a key focus on policy under Trump's administration has been to reset its energy and climate policy, reasserting America's energy dominance and independence, rolling black, clean energy incentives in favor of support for fossil fuels, and leaving the Paris climate agreement. Although there are many different policies and elements, the key things came together under the OB/BB, or one big, beautiful bill, which was signed into law in July. This reversed momentum injected into the energy transition by the Biden-era Inflation Reduction Act. To discuss this topic, my next guest is Julia Foods, a rose head of US East, who gave an optimistic keynote presentation at a rose energy transition forum in New York this year, focusing on the investment climate for power renewables post OB/BB. Welcome, Julia. Could you give our listeners a bit more context on the OB/BB? How did this and the Trump administration's policies more generally reverse Biden-era policies that incentivize renewables for thermal and renewable assets? How are investors adapting their strategies towards this new reality? Yeah, thanks, Richard. The biggest thing that the one big, beautiful bill act did was that it repealed the tax credits that Biden had extended with the inflation reduction act. So previously, we thought that projects were going to be eligible. Wind and solar projects were going to be receiving tax credits well into the next decade. Now those tax credits are being sunset by there by 2027, or if a project is under construction and has tax credits safe-harvard by 2030. That didn't happen in isolation. The Trump administration has also introduced tariffs and really a wide variety of countries. The challenges, we don't always know exactly how high those tariffs are. The rates are ever changing. So both the uncertainty and the increased costs are making it harder to build renewables. The third big change under the Trump administration is that permitting practices have really changed and gotten more difficult. So a lot of renewables require some sort of permitting because they're on land, owned or managed federally. Those processes have gotten much more administratively burdensome, and some federal offices have actually stopped granting wind permits altogether. Thanks, Julia. And what has been the impact of OBBB on the investment climate for thermal and renewable assets? Well, we've really seen a pickup in thermal activity this year, but all is not lost for renewables as well. So on the thermal front, I mentioned permitting is getting further for renewables, actually not just from a federal level, but at the state level. In many regions as well, permitting has actually eased up for thermal projects, in part because we see such a large growth in demand across the country. Some things got to build, in many cases, we need to build additional dispatchable projects. There are some holdups in the supply chain making it really, really hard to build anything new, but the momentum is there and we're seeing increased M&A activity across gas. Really like we haven't seen over the last couple of years. On the renewables front, there's probably much more cause for concern, but I will say it's important to contextualize that we're on track for a record year this year and next year based on the project that are advanced in interconnection cues. So we had an all-time high of 47 gigawatts worth of renewables installation in 2024. That number is projected to increase to 59 gigawatts in 2025, and even more than that in 2026. There was a project that are already being constructed right now, they're advanced in the process and they're likely eligible for tax credits. Beyond that though, all is certainly not lost, costs have gone up, but we're also seeing an increase in power prices being driven by some of those shortfalls in that growing demand, and also frankly by fewer renewables building. On top of that, in a lot of different states and regions, we see additional subsidy schemes that are available for renewables. For example, renewables portfolio standards that are subsidizing renewables project via renewable energy certificate, and that continues to make a strong business case. So we're seeing momentum. We saw a slowdown earlier this year in large part around the uncertainty and the ever-changing policy, but it's really picking up now, and we're seeing investors be very, very optimistic for the next few years. Thanks, Julia. I want to move us on to another topic, which is again pretty US-centric, though you could argue it is the global mega trend of 2025. This is of course the boom in AI and data centers. AI is fundamentally changing the way we live and work. From generative tools, rewriting how businesses create content through autonomous systems, transforming logistics, and predictive analytics reshaping healthcare and finance. On the energy side, the rapid deployment of data centers has far-reaching challenges and implications for power system and grids. Globally, market capitalizations of data center hyperscalers have stored this year, while data center electricity demand has also exploded, now equivalent to the consumption of a major economy like Germany. This surge in demand is forcing grids to adapt an unprecedented speed as they cater for data centers, as arguably their most needy customers. What are the challenges? Providing enough grid capacity at pace, accelerating transmission build out, managing system flexibility as demand becomes far more concentrated in data center growth zones while providing the highest levels of grid stability. In addition, ideally the power would also be green and cheap. I'm going to bring in Martin Anderson or was head of research in North America, whose team has conducted extensive research on the data center boom in the US. Welcome Martin, could you give us a sense of the pace and scale of the data center boom in the US? How many projects or gigawatts or terrible hours of data center load are we really talking about? And what are the challenges associated with building out power supplies for all those projects? Thanks Richard, 2025 has really been the year when AI ambitions have come up against the constraints of real world power supply. And there are huge ambitions to build data centers to enable that AI. There's approximately 37 gigawatts of data center capacity operational in the US at the moment. On top of that, there's approximately 23 gigawatts under construction and over 150 gigawatts in planning. This surge in demand is driving the first significant uptick in US power demand in decades. But crucially, this new demand isn't spread evenly. It's heavily concentrated in three regions, Northern Virginia and PGM, Texas and Arizona. Northern Virginia is already the world's biggest data center hub and still growing. Texas has become another magnet, especially around Dallas and Austin and Arizona is emerging as a key hub as well. So powering all these new facilities comes with major challenges. The biggest hurdle is simply getting them connected to the grid. The interconnection cues are incredibly backlogged and it can take years to get approval and the necessary grid upgrades as utilities are becoming overwhelmed with new requests. Facing these obstacles, data center developers are getting creative. One tactic for faster connection is building on-site power generation. Some are installing their own gas fire generators to power the data center, at least temporarily so that they're not entirely aligned on the grid connection being ready on day one. But this is only an option if you can access the gas turbine, which are in turn also becoming harder to procure, now of wait times of five to seven years. Developers are also looking at converting existing load into data centers. An industrial park in Phoenix had previously received its permits for a 400-megawatt connection and that's now being transformed into a data center. Earlier this year, core weave and AI cloud infrastructure provider attempted to acquire a Bitcoin mine operator, to convert the Bitcoin mining rigs into AI workloads. And while those plans fell through in October, there's thus highlight that the industry is doing an all-of-the-above approach to procure power. A combination of on-site generation, delaying retirements of all clouds, and new power purchase agreements, whatever it takes, which underscores a key point that the scale of this boom is massive, but the real test is speed. This is a race and there's potentially huge gains to the early winners of AI, therefore a huge amount of money is being thrown into these problems. And over the next few years, we'll see a frenzy of activity to keep up with that demand. Well, to the investor and system-wide impacts, then, of bringing data center loads onto the grid this fast, what does it mean for the economics of renewables and batteries for security of supply? So from a market perspective, adding so much demand so fast, it's going to push up electricity prices and it's going to tighten reserve margins. So that in itself is a clear incentive to build more power plants. And indeed, many developers are scrambling to bring forward new projects, especially renewables and energy storage to meet this surge. Data center operates to themselves, often prefer clean energy to meet sustainability goals. And so they're directly helping finance a lot of new wind and solar farms. And this comes in the year when the one big beautiful bill act was passed, which will phase out federal tax credits from renewables from 2030 onwards. If demand for data centers continues at a pace over the coming years, then that could support higher PPA pricing for renewables projects and offset the loss of tax credits. And a crucial element here is the role that battery storage can play in supporting new data centers. Battery storage has long been integrated into data centers in the past as backup generation to provide a UPS and an uninterruptible power supply. But this is typically not used and is very much a last resort to ensure operations are not lost. But as battery costs have come down, alternative use cases are now being further explored. One option is to accelerate load into connection studies. By deploying a battery strategically on the network, it's possible to reduce the need to upgrade lines when connecting a new data center project. Another option is to use the battery to smooth the load profile. Data centers can be huge and their load can swing wildly across seconds as the workload changes and models run on the chips. And you can see loads swing go from 20 to 80% across individual seconds, which presents a new challenge for good reliability. But also an opportunity for battery storage, which can ramp up and down very quickly with that change in load. If we don't see the data centers incorporated smoothly into the grid, then we will see higher prices. And if we don't see greater reliability, then that's going to lead to even more pushback from local consumers, which could ultimately slow the pace of data center deployment. So ensuring healthy reserve margins and reliable grid is very much in everyone's interests. And batteries present an opportunity to ensure that new data centers can be connected as fast and securely as possible. I'm going to move us on. For the next segment, I want to take us away from the US specifically and focus on a topic which has been rising back up the agenda in many countries and power markets globally. This is around how to ensure power system reliability and security of supply. So to some extent, this topic never really goes away since electricity is so critical to our lives and to our economies. But the combination of extreme weather events such as storms and heatways, aging grid infrastructure, rapid renewable build out, geopolitical and cyber risks, all seem to have come together to present a heightened perception of risk around these issues. Now in 2025, we've seen some notable power system outages and failures globally in particular. The blackout across the Iberian peninsula in April 2025, which knocked out power to 60 million people for 10 hours. A smaller but very significant blackout in Australia in March on the back of cyclone Alfred, which left over 300,000 people without power, as well as repeated warnings connected with system stress during summer heat waves. In the US, there have been various outages and system events caused by winter storms and heat waves. I want to get the lowdown of what is happening in these markets by drawing in aurora's experts from around the world. We want to understand what were the causes of these system outages and what are the system operators now doing to manage the situation. Let's start with the experience from Iberia, and I'd like to bring in my colleague Kristina Rentel, research leader in Southwest Europe, who is uniquely positioned to comment on the events in Iberia. Welcome Kristina. I know that we're still awaiting the final report on the Iberia blackout, but could you paint a picture of what happened in the build up to the blackout and what factors may have contributed to it? Yeah, so we are still waiting for the root cause analysis report. It's the technical name for it, but we have had some factual reports coming out on both a national and international European level. So what they basically highlight is that in the build up, and here I'm talking a maximum of about half an hour before the blackout, we saw oscillations in the system, and this is oscillations on the voltage. Oscillations are problematic in the system, basically because it does mean that the system can't absorb disturbances very well. So you react to one issue, the system swings, you basically have to do the complete opposite reaction, and this just causes further oscillations in the system. And also, if those oscillations are not actually dampened quickly enough, they can actually trigger protective trips, and this is exactly what we saw happen. A few minutes before the blackout, as we saw some generation assets go offline, and that started in the south of Spain, basically causing a cascade up through the whole peninsula, and even affecting some of the very south of France as well. One of the key factors that actually might have contributed to the blackout is the lack of inertia on the system, and just excuse me as I get a little bit technical. So inertia comes from rotating masses in synchronous generators, basically gas. inertia doesn't actually help directly with the voltage issues for that you need reactive power, but systems with high inertia usually do have a lot of synchronous machines or a lot of gas online, and they do provide reactive power. And therefore can help with the voltage issues. So lack of inertia to combat those voltage oscillations is considered to be one of the key suspects for the Iberian blackout. Thanks, Christina. Was the government and system operator done in response to this experience then, and are there lessons that we can draw? The first thing the system operator did was basically going into safe mode. Since the root cause wasn't or isn't still 100% confirmed, the TSO basically wanted to ensure that there was as much gas on the system, so in order to potentially be providing that inertia that I mentioned, and making sure that the system is as stable as possible until they found out the exact root cause. And they did this by activating those gas assets upwards in the technical restrictions market. This lasted for a few months, so we saw a big increase in volumes and also incidentally cost to the consumer, which passed through onto the bill. When it then became clear that the big factor was the oscillations in the system, the TSO and the regulator implemented some temporary measures, basically including shifting as many of those volumes in the technical restrictions market to the day ahead, rather than in real time, just to give them time to react and be as proactive in the activations as possible. Increasing the ramp rate for renewables from two minutes to 15 minutes, again giving them time in real time to react to any system changes, and also tightening the reporting penalties and the requirements included in voltage control operating procedures. What can we learn from this? So I think a big thing is to think holistically about how we actually integrate renewables into the grid, so not just about the clean energy that they bring, but also the impact on voltage, frequency, inertia, etc. And also think about the system as a whole. So one of the key things that we were missing on the day of the blackout was flexibility in the system, specifically I'm talking here about batteries. And so batteries can help provide all of the services I just mentioned. And ensuring a clear regulatory framework and incentivising batteries in the right way, for example, a paid primary reserve and the long awaited capacity market could help mitigate some of those issues. Thanks Christina. Next let's move to Australia. As I mentioned we saw a significant blackout in Australia this year and generally the system seems to experience quite a number of outages and systems stress events. At the start of 2025 there was some pretty extreme heat waves and reports warning of strain power supplies and it seems like AEMO the system operator in Australia is again concerned in the run up to the summer heat waves issuing further reserve warnings. Now let's bring in my colleague Andrew McGregor, research leader covering the Australian markets, who's looked at these issues in detail. Welcome Andrew. Could you tell us a bit more about the overall state of power system reliability in Australia? What are the key concerns? Is the power system becoming more exposed to weather related volatility? Thanks Richard. Australia's electricity system remained broadly reliable in 2025, but it's entering a critical transition period. The biggest concern isn't just a lack of energy generation. The ability to keep the grid stable and secure as the country retires large coal-fired power stations and replaces them with renewables and storage across the national electricity market. Coal plants don't just generate electricity, they also provide inertia and system strength, which help keeps voltage and frequency stable. As these plants retire, for example, a rowing in 2027, Yelorne in 28 and Gladstone in 2029, the grid will become more reliant on new technologies like synchronous condensers and grid forming batteries to maintain stability. The reliability of the system hinges on whether this new infrastructure comes online before the coal plants exist. Delays could lead to shortfalls or instability during periods of peak demand or extreme weather. At the same time, the system is becoming more exposed to weather. Renewables like solar and wind are variable by nature and extreme weather events, such as cyclones, heatwaves and storms, are becoming even more frequent and intense. These events have already caused major outages in 2025, including a 300,000 person customer blackout during cyclone Alfred. In 2025, the Australian electricity market operator released a system security plan, warning that by the late 2020s, acts of the grid, notably Victoria and New South Wales, could face system strength deficits after coal closures, meaning that the grid could become unstable during disturbances if no action is taken. The report identified critical short-term transition points in New South Wales and Queensland, which AMO sees as significant issues. Transgrid, the New South Wales Transmission Network Service Provider, is attempting to expedite synchronous condenser procurement currently on track for 2028, but unlikely to come online before arirings scheduled retirement, which would likely result in activation of transgrid system security contracts or AMO operationally intervening up to 30% of the time at significant cost to consumers. In Queensland, minimum operational demand is projected to fall by 250 megawatts per year through to 2030 when coal generation begins to exit. There's a growing shortfall in the ability to increase demand during the middle of the day to require thresholds, which urgent need for increased emergency PV backstop capacity by winter 2026. And Andrew, what are the implications of this fall policy makers and for investors? What can we learn from the Aussie experience of what to do or also what not to do? The Australian electricity market operator has emphasized the importance of giving early notice for coal closures because they're so large and important to the system. Iloran's 2028 retirement was announced years in advance, giving time to plan replacement capacity. Even in New South Wales, although delays to delivering new synchronous condensers and renewable generation and battery storage capacity have raised uncertainty around the system or the ability of the system to continue to operate without ariring. Transparency on closure timelines has allowed this risk to be assessed in advance. This contrasts with past abrupt closures, for example, Hazelwood in 2017, where the French company, Orgie, only gave five months notice before shut down, causing price spikes and reliability issues. Investing in grid-forming technologies is really important in less interconnected systems. Australia is deploying large-scale battery, for example, the 815 megawatt wiretower super battery in New South Wales, and synchronous condensers to replace the stabilizing ability of coal plants. These are essential for secure, renewable, heavy, and less into connected grid. In AEMO's transition plan for system security, South Australia received the most clean bill of health compared to all the other mainland states, stating that South Australia had no system strength deficits as compared to the other states. In large part, due to the four synchronous condensers that were built to provide system strength. The market operator is even forecasting that from 2028, South Australia could be running with zero gas providing backup, once the project energy connect interconnector is fully commissioned. Gas generation will become increasingly critical for system security as coal retard. AEMO has identified that gas turbines fitted with clutches, at design or in retrofit can act as synchronous condensers, providing an opportunity for system strength and inertia provision even when they're not generating power. AEMO is also encouraging investors to consider the above as well as policy reform to incentivize investment in system security technologies such as this. Lastly, 2025 showed how extreme weather can cause massive outages and significant price volatility as well. Governments who consider climate resilience when planning generation network and transmission investments as well as emergency response. And volatility is an important feature of business models for flexible assets like battery storage and other peaking generation and should be captured when assessing project viable prior to taking our final investment decision. Finally, I'm going to come back to the US. Again, it seems like there's a perfect storm of factors, affecting grid reliability due to surging electricity demand from AI data centers and electrification more broadly. Accelerated retirements of coal and gas plants without equivalent firm replacements and aging infrastructure combined with supply chain bottlenecks for critical components like transformers and high voltage cables. This issue was acted on early in 2025 with the Trump administration declaring a national energy emergency and issuing executive orders specifically to preserve critical resources and streamline emergency interventions. The grid reliability though is fairly widespread across the US, but particularly in markets like ERCOP, Kaiso, the Midwest and Northeast regions as well. The rules have been across these issues in many US markets, culminating this summer in the publication of a public report on the US's Reliability Challenge and the value of flexibility. You can find it on our website. My colleague Livye Bofilz heads up a rules activities in the US Central region and recently he gave evidence to the Electric Reliability Council of Texas or ERCOP system operator, providing an assessment of resource adequacy needs in ERCOP and the impact of market design changes. So it is extremely well placed to tell us more about reliability issues in the market. Welcome, Livye. Could you describe for our listeners what's the current situation and outlook for grid reliability and security of supply in ERCOP? How is this impacted by weather volatility and the rapid rollout of date centers? Thanks Richard. The situation in Texas is fairly unique at the moment. So we had a major reliability event back in 2021 during winter storm Yuri when ERCOP had to shed close to 30 gigawatts of load for several days. Since then obviously reliability has been front and center of legislative and regulatory discussions. And at the same time now Texas has been seeing some of the fastest load growth in the United States while adding the most renewable and storage capacity. In addition Texas tends to see both extreme and fairly volatile weather conditions. So we can have winter storms here where temperatures drop below 10 degrees Celsius or 10 degrees Fahrenheit as well as summer where sometimes daily maximum temperatures hits 38 to 40 degrees Celsius or above 100 degrees Fahrenheit for three months in a row. So as you can imagine all these factors make a fairly challenging situation to manage from a reliability perspective. So now adding on top of all that is the current data center investment rush a lot of which has been focused on Texas. And so ERCOP is looking at this looming load growth understandably is very concerned about having the right investment signals to incentivize the right kind of capacity to come online. So expand on this what does system operators need to do differently to manage the reliability challenge? How important is it to harness flexibility from thermal, from batteries, data centers or other users? And how can this be incentivized? It's a great question. So the challenge in an energy-only market like Texas is that you cannot really direct investment towards a certain type of technology. It's up to the market to solve that equation. Right now we've had a mild summer and market signals for investment are actually fairly muted. What it tells you really is you need to retire capacity and stop investing, which understandably is making ERCOP very nervous when they think they need a lot of fast ramping capacity to handle volatility and load growth. So in that context ERCOP is trying to be creative. They're trying to design a product to incentivize the kind of long duration dispatchable capacity, inflexible dispatchable capacity they think they need from a reliability standpoint. And in Texas as a lot of you may have heard centralized capacity markets are not particularly popular. So ERCOP's taking the route of designing an hourly and salary service product to provide investment signals for resource adequacy. The idea is you would get paid based on availability during the hours that ERCOP deems to have the highest reliability risk and under a set of sort of eligibility criteria to have the right kind of technologies get the payments that ERCOP wants to provide with a typical hourly procurement of an salary service and without the sort of centralized season or annual capacity auction. So that that's really the goal here is how do you incentivize that flexibility, that dispatchable generation to cover this reliability risk. I'm going to leave us on to our final theme, which is around the challenges and solutions to integrate renewables into power systems. Renewable penetration is rising sharply in many countries around the world as renewables projects are deployed at an unprecedented pace. In 2024, renewables capacity reached almost five terawatts of capacity and contributed 10,000 terawatts hours of power or 32% of total power generation that is globally. We almost certainly passed the five terawatts threshold during 2025 with a further 800 gigawatts of renewables estimated to have been deployed this year. There is significant regional variation, so the renewables penetration varies from generally over 60% in Latin American markets, over 40% on average in European markets, but lower, more like 30% in APAC and North American markets in general. The rapid pace of renewables deployment is leading to a number of issues and challenges, though, which we see playing out in markets around the world in our analysis. Firstly, more renewables generation increasingly leads the periods of oversupply relative to demand. This can cause increasing incidence of zero or even negative prices in wholesale markets, as well as economic cutelmen, and this presents a major downside risk for renewables developers than investors. Second issue is around grid cutelmen. As renewables sites are often optimized for renewables resourced, rather than proximity to demand, this places additional loads on the grid. Generally, the investment in grids is lagging far behind that of renewables, and in many cases, this is already leading to a sharp increase in grid constraints, with renewables being constrained off the system. Again, this presents a downside risk, particularly in markets where this cutelmer is not compensated. Finally, as we get to higher penetrations of variable or non-dispatchable renewables, this adds a lot of volatility to the system. This can be managed through investments in flexible power solutions, such as hydro, batteries, thermal, demand-side response and so on, but it takes a really proactive approach from governments and system operators to get ahead of this challenge and avoid it causing instability or in the extreme types of blackouts we heard about earlier. I'd like to illustrate these challenges with real life examples from around the world. We'll start again on the specific challenges around renewables integration and how this impacts the renewables investment climate, and then afterwards, once we've understood the challenges, we'll unpack some potential solutions. The first example I want to focus on is Europe, where since 2022, we've seen an acceleration in renewables deployment under the repower EU program in response to the Russia Ukraine war as a mechanism to reduce dependence on Russian gas imports. Europe has been very successful in reducing its reliance on Russian gas, which was previously around 35 or 40% of the total gas supply prior to the Ukraine war, and is now around 10%. Indeed, the European Commission is now taking further steps to limit or completely ban Russian gas from the mix. One of the side effects of the renewables boom, though, has been a corresponding increase in the frequency of negative price periods in the wholesale market, as renewable generations saturates the market at times. 2025 has seen a record number of negative price periods in many European markets. I'll draw in my colleague Rebecca McManus, lead expert in European renewables, who has been watching this trend closely in the past few years. Welcome Rebecca. Could you give our listeners some more details on the trends around negative prices in Europe? How often do we see negative prices and how low do they go? And for our listeners can you explain what is driving those prices below zero? Thanks Richard, maybe just a focus on the key trends to start with. So this year has been a record year for negative prices in Europe, with most major European markets actually exceeding 2024 values already by midway through this year. For example, Spain, the Netherlands and Germany have each recorded record prices of over 500 hours of negative prices this year at this point. To put this in perspective, the European average last year was around 267 hours in 2024, so considerably higher than the average of last year. So what's driving this? Maybe to move on to that point? The main drivers are kind of fivefold and often these are acting together. Firstly, we have production from renewables, so especially renewables that are under price insensitive subsidies. So this means that they will continue to generate even when prices turn negative. Secondly, inflexible plants like coal and nuclear that cannot easily ramp up or ramp down, these plants will continue to operate regardless of the market price and therefore amplifying the effect. Then if we add in other key factors, so the last three key factors such as strategic bidding from renewables that have access to multiple market revenues as well as cross-border imports of negative prices and incentives like guarantees of origin, you have yourself a recipe for volatility within the market. Looking forward then, what is the outlook for negative prices? Do we expect them to continue to increase further or is a turning point in sight? Yes, in the short term, negative price hours are expected to remain high and may even increase further as renewables continue to be added and flexibility solutions are lagging behind. This means that asset owners will definitely need to adapt with strategies such as colocation of batteries in the short term. However, we do see a turning point on the horizon and our modelling suggests that by 2035 we will see negative prices begin to receive significantly. So the key drivers for this shift that we see by 2035 is due to rising electricity demand, the build out of flexible technologies such as battery storage and also policy reforms that we're seeing today which is phasing out prices sensitive subsidies, so not remunerating in those negative price hours anymore. In Germany in particular, we see the negative price hours decrease particularly with the coal exit but also the continuous build out of flexible demand technologies within the market leading to negative prices as it's reducing after 2030. So in summary, negative prices are definitely something that will remain a feature in European power markets for at least the next decade and potentially beyond this, in system flexibility measures are not prioritised in Europe. Many thanks Becker. Next, I want to turn to Latin America which is an even higher renewables share than Europe. In particular, our focus in Brazil and Chile where Aurora is already active in providing power market analytics. Brazil has amongst the highest renewables share in the world at nearly 90% of generation. Historically, it was heavily hydro-focused although the hydro share is declining due to droughts and the fast growth of other renewables sources such as wind and solar. Negative prices have not been an issue, unlike in Europe as in Brazil that's a price floor, but Brazil faces increasing problems with Greek constraints moving power from renewables focus regions to demand focus regions with 2025 seeing a surge in solar-catalement at extreme levels. Chile on the other hand is quickly emerging as a global leader in solar and due to very high radiance levels, but Chile has a very long-thin power grid with renewables located far from demand. As a nodal system, this results in both cutelman and low prices for renewables at double whammy for investors to manage. I'll bring in Inesh Gaspar who is Aurora's research lead for Latin American markets to give us further details. Welcome Inesh, could you say a bit more about the challenges of renewables integration in Brazil and Chile? Are there specific or unique features of these markets that we need to consider to appreciate this fully? I reach out. Thank you so much for bringing Latin to the retirement conversation here today. Yes, there are a few very market-specific features that matter for Brazil and Chile, and I think the key ones are three. The extreme special mismatch between where generation and demand are. Then the second one, the fact that they are hydro domain and systems. And the third one, which is more Brazil-specific, but still applies to Chile, is the distributed generation and the lack of operation control over it. On the first one, the extreme special mismatch between generation demand, both countries, every renewables build far away from most centers in Brazil, for instance, 80 percent of utility scale is in the northeast and demand is not there. This makes curtailment structural issue. Then second, both systems are hydro heavy. This is specially true for Brazil with around 60 percent, but also for Chile with around 30 percent of hydro generation. While hydro helps with flexibility, I really think that as many people say Brazil is not just a big battery. You have minimum generation, you have reservoir constraints, ramp constraints, so you end up having a large block of inflexible capacity, and this also forces you to do renewable cuts. And finally, the third one, which is the distributed generation that you have in these systems, especially in Brazil, you have a lot of solar in the distributed network that the system operator cannot dispatch and that cannot curtail. So this shifts all the balancing pressure of the system onto utility scale assets. Thanks, Inesh. What's the outlook then for grid curtailment in Brazil in particular? What are the key factors which could influence this in the next few years? Curtailment right now is already material in Brazil. Recently, wind curtailment reached around 20 percent of curtailment and solar on 30 percent. These numbers are massive, and actually most of this is in energetic curtailment this year. While we can say if the situation is going to be exactly the same over the next years, we see a problem here that unless something is done, it's not going to disappear on its own. So looking ahead, I actually think Chile offers a useful reference. In Chile, we have a nodal market. So this nodal pricing already created strong economical signals, both on pricing and on curtailment. And very quickly, it made standalone intermittent renewables, especially solar, completely and financially without storage. So the response here from investors and from the regulator was to quickly regulate these assets, enabled them to get capacity payments, and the investors rapidly deployed batteries well before grid reinforcements have been completed. While I think Brazil is also moving in that direction because it already has a battery capacity auction planned, it's also important to say that storage alone won't solve everything. In Brazil, we have a deeper issue, which is the fact that contracting structures mute the price signals at an hourly level. This is a home sequence of a market that was weekly until 2021, right? So while yes, curtailment is today's problems and while yes, we still see that some curtailment will exist in the medium and long term, going forward risks like interdivalatility and sub-market spreads matter even more and they are not currently being accounted for. And pricing these new normal correctly is exactly where our RRM has been focusing their work over the last year. The third example that I'd like to draw on here is Japan. Japan's renewable share is currently around 28% with the majority of power generation coming from the thermal and they share from nuclear continuing to rise slowly post-ficushima to around 8-9%. The renewable share doesn't actually stand out as particularly high and yet Japan is already facing some significant issues around renewables integration with curtailment surging to record levels in 2025. This seems to be driven by a few factors. Similar to many places, renewable resources are located away from the main demand centers. The Japanese market has only recently liberalized and still lacks economic incentives such as negative prices. Then there are also some market specific issues. Japan lacks a robust framework for transmission development while it operates two different grids at different frequencies adding further complexity and reducing resilience. Lastly, Japan has been pretty slow to deploy battery storage which could otherwise help to alleviate these challenges. Let's hear from my colleague Yamato Kawamata, whose team has produced extensive analysis on these topics. Welcome Yamato. Could you expand on my high level explanation of the challenges around renewables integration in Japan? What are the key issues? Thanks Richard. Over the past decade, Japan has seen a rapid increase in renewable deployment, particularly solar. Since the introduction of feed-in-tariff or if IT scheme in 2012, solar capacity has expanded a significant country and today Japan ranks among the top five countries groovery in terms of solar capacity. However, as renewables have scaled up, integration challenges have become increasingly visible. Brothers speaking, these changes fall into two categories. Economic cutlerments driven by supply demand in France and a physical grid congestion. On cutlerment, 2023 was a turning point when economic cutlerment became widespread outside Tokyo for the first time. The T2025 takeaway is that this issue has not gone away. A cutlerment has persisted as supply continuously exceeds demand in civil regions, making it the core economic risk rather than operation of note. The second challenge is grid congestion. Japan's geography plays a big role here. Renewables are clustering in resource rich but demand-light regions. Grid development has lacked renewable growth, making congestion increasingly structural with grid connection cues stretching into multiple years. Thanks, you're right too. So, what is the government and system afraid of doing to address these challenges? And what is the outlook? I would highlight two measures here. First, Japan is an actuary-shifting project from the FIT scheme to feed-in-premium or FIP. This exposes Renewables more directly to market signals, encourages better operational behavior and creates stronger incentives to co-located road streets. From the system perspective, this helps mitigate cutlerment risk and improve grid stability. Looking ahead, additional FIT and FIP cutlerment lose changes planned from 2026 next year will further impact asset economics. Our second on grid side, non-form connection rules have moved into real-world operation. Assets can connect faster but they accept cutlerment risk during congestion. For battery-stressing particular, 2025 makes step change. As charging restrictions have been introduced in practice for the first time, batteries are now responding not only to places but also physical grid constraints. So, overall, these measures support system stability but they also change asset economics. That's why quantitative analysis is essential and we're all on our come team. Many thanks, Yamato. Those three case studies were all instructive in helping us to understand how the surge in Renewables deployment could quickly lead to issues around economic and grid cutlerment and system stress. Often these effects are highly non-linear as the system reaches tipping points, which is why in all of these markets Aurora has developed detailed power flow models to forecast cutlerment down to a zonal or nodal level. Whilst each of these case studies illustrates some significant challenges, I don't want to leave the impression that it's all doom and gloom and unmanageable and rather look for solutions in the form of technologies, business model innovation or market design. Let's start with the technology angle then. Could long duration batteries be part of the solution to manage Renewables integration? This idea is certainly caught on in Italy this year, where the system operates a turner around the first auction for the so-called Maxis scheme. This is a dedicated support scheme for the new long duration storage assets in Italy. The context here is that Italy faced growing challenges around Renewable integration with a rapid expansion of solar and wind capacity in recent years, which is in many markets is located far from the demand centre, so in the south of the country. The Maxis scheme is designed to manage this issue by offering support for new battery and pump storage projects in the south of the country, particularly focusing on longer duration projects. I'll bring you my colleague Magdalena Toretto to give us more details. Magdalena, could you provide more context on the Maxis auction? What issues was it designed to manage and what was procured through the auction? Thank you, Richard. The question behind the introduction of Maxis scheme in Italy was a very practical one. How can we achieve ambitious renewable targets while keeping the power system secure and stable? According to the fit for 55 targets, Italy will face a massive expansion of Renewables by 2013. Basically, the total installed capacity will double in the next five years. So the system will increasingly face structural overgeneration, especially during solar hours. And to manage this growing complexity, the system needs flexibility, particularly at the intraday time scale. This ledger means the ability to store solar energy during the central hours of the day and release it later when the demand is higher. The target ISO estimates a need for around 72 gigawatt power of storage capacity by 2030 to ensure this renewable integration. And 50 gigawatt power must come from new utility scale assets. This is where Maxis scheme comes in. Maxi is a dedicated scheme for new utility scale storage assets designed to procure load shifting capacity that enables renewables growth while supporting grid security and system stability. The need for storage is not uniform across the country. Most utility scale solar and wind is expected in the south and in the islands where the local demand is relatively low and the original risk is higher. By contracts in the north, where around alpha national demand is concentrated, the TSO does not foresee a need for new standalone assets. And storage deployment is expected to be mostly more scale and co-located with PV. In September, we had the first day Maxi auction. And the total target was 10 gigawatt power with 7 gigawatt power concentrated in the south zone alone. The full target was allocated. And while for our duration was set as the reference duration by the TSO since they contribute more to system adequacy for the same equivalent energy capacity, the auction design that is pay is beat on a Euro megawatt power basis favored the longer duration and the larger scale assets due to their economies of scale. As a result, the average project size was about 100 megawatt and the average duration about 7 hours. 14 projects were awarded in total to selling companies with one operator securing around two-thirds of the awarded volumes, leisurely concentrated around a single grid area. Overall, the results confirm that the Maxi scheme provides a clear route to market for large scale and long duration storage assets in Italy. So the first Maxi auction turned out to be extremely competitive with very, very low bits from participants. Why were prices driven quite so low? And what's the outlook for future auction rounds? The entire thing that got our target was awarded with participation volumes around four times the available capacity. The result was a weighted average awarded price of about 13,000 euros per megawatt power, which represents a 65 percent discount compared to the auction cap of 37,000 euros per megawatt power. To better understand this result, it's helpful to look at how Maxi is designed. Maxi is a support scheme designed to the risk investments by providing fixed long-term payments and by largely removing the exposure to market volatility. So winning projects are awarded 15-year contracts with limited revenue stacking opportunities and storage operators can only marginally benefit from the market revenues. As a result, most of the revenue stack is fixed and regulated. This means that competition in the auction is driven almost entirely by investment cost optimization and return expectations, rather than by expected profit from merchant trading strategies. The lower-warded prices reflect very competitive cost assumptions and relatively low expected returns in line with the infrastructure type assets. These dynamics were reinforced by a broader context of declining battery index and by lower return expectations across the entire supply chain. Finally, some winning projects were able to push beats even lower thanks to project specific optimizations such as the use of brown field sites and by strong competitive pressure created by the design to secure a road to market in Italy. For additional auctions are expected, one of which will be in 26 and Maxi is up to 40g of power to allocate across the next two rounds with significant volumes expected in the two islands. Thanks so much, Magdalena. It seems that standalone longer duration batteries could definitely be part of the answer, especially with battery system costs now at all time lows. But should batteries only be standalone, as in the Italian example, or also co-located as part of an optimised portfolio? Let's jump across to India, where they have a completely different approach to managing renewables integration, which in simple terms is to push more of the problem onto the developer by requiring to bid firm, despachable power. India's renewables capacity is growing very fast, albeit from a lower base in a coal-dominated system. Whilst in most markets around the world, renewables can be paid as produced to their generation profile. In India, the government runs firm and despachable renewable energy, or FDRE, fenders, which require you to deliver, as her name suggests, firm, despachable power by combining renewables and storage all in one package. 2025 saw a significant increase in the use of these FDRE tenders in the Indian market. I'll bring in Debra Tagos, or as market lead for India, whose team has been working with clients across the country on how to analyse these FDRE tenders. Great to have you on the podcast, Deb. Could you tell our listeners a bit more about the FDRE model in India? What is unique about this model? And why was it designed in this way? Thanks Richard. So FDRE firstly stands for firm and despachable renewable energy contracts, which are in a way of first of its kind globally. What it does is, instead of the plain vanilla pay as produced, you know, contracts, the FDRE contracts stipulate a particular load profile that the generator must meet, vis-a-vis the demand pattern provided by the off-taker. Now, why has this come about? There are two ways a power system solves for peak demands, one way is for the utility to really source all the generation and needs and then optimize at its end. Due to multiple reasons, for example, you know, nascent scenes, some of the discourse abilities in India, but the government decided is the developers can provide sort of the load following curves, and in a way, shifted the risk profile of ensuring the generation as per the off-take profile to the generator. Now, what this is done is essentially introduced a risk premium, because as you can imagine, a typical FDRE contract would have certain peak periods in the morning and the evening, and in order to ensure that those load profiles are met, failing with the contract penalties are quite severe, the developers have had to oversize. And in order to inculcate the different risk elements, for example, merchant risk, generation risk, contractual risk, so on, so forth, the realized tariffs have seen a significant premium to a usual PS-produced contract. Thanks, Deb. So, what are some of the challenges and complexities associated with bidding into the FDRE tenders? How can you optimize your bid to succeed? Yeah, and I think this is a very cool piece of, you know, analysis where we have worked with, you know, most of the leading developers and also lenders on FDRE project financing transactions. So, let me quickly lay out what an FDRE tender typically looks like, an FDRE tender actually has multiple facets. So, for example, there could be a peak only tender way you need to provide a short power at certain peak slots, typically in the evening hours in India, or it could be an a short peak profile way you need to provide power through the day, but there's a certain minimum demand fulfillment ratio that you need to fulfill for the peak hours. There are six to 10 pm in the evening, for example, or it could be a load following profile. Now, in order to assess in India's bidding arena is super competitive, and therefore you need to have, you know, very competitive, reverse auction discovered tariffs, and that needs to meet your threshold IRRs, and to do that, you really need to understand firstly, you know, what will be the nature of the peak profile throughout the 25 year period, which is the usual tenure of an Indian sovereign backed contract. What that also means is depending on how your site is, whether it's, you know, a high radiation on solar or wind or both, the optimal configuration of solar wind and battery really varies, depending on the nature of the contract, as well as sort of the location of your assets. In addition to this, there are several levers provided in the contract that you could potentially optimize, and we've been doing that with several developers. A few of them are one, a demand fulfillment ratio, with basically means of the total demand, you know, over a period of time, and this is typically split during the peak hours and non peak hours, the certain DFR percentage you need to meet, but there's a flexibility provided in terms of what you choose as the declaration. Second is capacity utilization factor. Typically, developers want to have a higher year factor. The utilities or the discounts, as they're called in India, typically want to lower year factor, but there is a sweet spot of declaration of CUF, because on the lower side, you are on over penalties, and on the excess side, you sort of typically have higher Kpex because you're over building without lesser utilization for the particular contract. And therefore, the sweet spot of CUF is super critical. And last but not the least, how do you size your battery and how do you optimize your battery is super, super important in terms of getting the configuration right? And lastly, there's an optional clause of being able to contract a part of the delivery requirements from the merchant market. So India has three key markets, day ahead, green day ahead, and real time market. So there's an opportunity to procure about 5% of the power procurement need from the green day head market, and we have been able to see improvements while unlocking that lever. Overall, from our work, we have seen more than 10 plus percentage savings on the Kpex of penalties, as well as due to three percentage point improvements on the IRR. Our final case today will look at how the market design can be changed to provide locational signals to market participants. In a sense, if one of the problems of renewables integration is that renewables often locate away from demand, and therefore cause grid congestion, then how can the market design provide appropriate locational signals to incentivize the right behavior? This market design question has been live for several years now in the GB market, since the review of electricity market arrangements kicked off in 2022. This reached fever pitch in 2025 with a lively debate between the camps for or against locational marginal pricing, and at the same time, grid constraint costs continue to exceed £1 billion per year. In the end, the government decided against so-called nodal pricing on the basis that it could create investment uncertainty. Precisely at the time, we are racing towards clean power targets for 2030 and beyond. There were also clear political challenges around the post-code lottery or distributional effects of LNP, which would have created winners and losers up and down the country. Instead, GB will keep a single national wholesale electricity price, but reform some of the other locational signals around this, which come through the balancing mechanism and network charging. This will be complemented by moving towards greater top-down spatial planning, accelerating grid deployment generally, and better management of the grid queue. Let's hear from my final contributor, Renave Menon, who is a senior associate in RGB research team. Welcome, Renave. I think, in the interest of time, let's avoid raking over the debates around locational marginal pricing, as this idea has been put to bed in GB for now. Instead, could you help our listeners by unpacking the government's alternative solution, which is expected to be unveiled very shortly. What are the key proposals you're expecting to see in the government's next announcements? Thanks Richard. So yes, the dust kicked out by the relatively fierce debate around the potential move to zonal pricing and written and starting to settle, and while we're still waiting for the government's official plan on reforming current market arrangements, the broad pillars of the strategy are becoming clearer. Now, at a high level, as you've already laid out, the GB system has currently reached a point where much greater coordination is required, particularly as we accelerate the decarbonization of supply through rapidly integrating renewables. The mechanisms that are meant to provide location and operational signals in the market today are either absent or incoherent, and there's been no shortage of commentary on this of the past year. Now, under reform national pricing, the government's response to this challenge is to lean heavily on central planning, and at the heart of this is the proposed strategic spatial energy plan or SSEP, which is intended to act as a blueprint for where generation, storage and demand should be located across the system to maximize efficiency and coordination. Now, in theory, they should bring greater predictability, and crucially align investment decisions with long-term plans to reinforce the grid, and that bit of the alignment is meant to come from integrating the SSEP with other planning frameworks such as the CSNP, which is a network plan, and the regional energy strategic plans. That said, while this kind of coordinated planning should help address some of today's key system bottlenecks, the challenge will be execution, the scope and complexity here are significant, and as modelers ourselves, we see just how difficult this is going to be, particularly in a fast moving technology landscape. The process has also had a slightly shaky start, and timelines are beginning to slip, so we're now expecting a draft SSEP only in early 2027. Now, the other key area that's likely to see a meaningful change going ahead is the Tynua's charging regime, which has historically been notoriously difficult for developers to navigate last due to its unpredictability and volatility. Now, there's lots of options on the table, but the most interesting one is CRP442, which would allow generators to lock in a fixed tariff at the point of investment for an extended period, so this should introduce some much needed predictability, and also sort of move the Tynua's to be a mechanism to reliably recover network costs in a world with more center planning, as opposed to it acting as a proxy for locational wholesale pricing. Thanks for that. How effective is Tynua's or the transmission use of system charges as a locational signal? How does developers and investors forecast future charges currently, and is there any way they can do better? So, I think it's fair to say that there is now broad consensus that Tynua's failed to provide an effective locational signal in Britain, and that largely comes down to things. A, a lack of transparency in how these charges are calculated, and B, a high degree of uncertainty. So, the charging methodology itself is quite complex, the most market participants, and is based on detailed load flow modeling that Nisto does. But this results in this sort of relies on a wide range of assumptions around future grid build out and generation patterns, and really sort of results in extreme volatility, and in some cases we've seen charges double over the three are peded as a lot of the underlying assumptions change. Now, this level of unpredictability ultimately increases the cost of developing assets because it places this risk on projects that are unable to respond once they are built. As a result, Tynua's line item is often one of the most heavily contested elements in a transaction, especially certain occasions, and historically the standard bankable approach has always been to take Nisto's 5-year view and hold it flat beyond the full class horizon. Now, we do think there's a better way of being this, and one we've spent a lot of time developing over the past year by essentially deconstructing a version of Nisto's network flow modeling, and we've achieved this throughout grid modeling capabilities, and what we've been able to really show is that one of the biggest drivers of the Tynua's has is actually your view of network delivery timelines, and this is where Nisto is often constrained to using fairly optimistic views of delivery based on published plans, but when you apply a more realistic assessment of delivery as we do in our grid scenarios, that view can shift quite materially as indeed it does as you approach a delivery year. Similarly, relying on the 5-year view alone can result in a significant over and under forecasting of the charges, and this is where our long term Tynua's forecastly fills a gap and is available through our grid product now. Thanks so much for now. And with this, I'll start to wrap up our special edition podcast and review of Global Energy Transition Trends in 2025. As you can see, there's been a flurry of market and policy developments this year, and it's definitely kept the team at Aurora Busy providing analysis and insights. I'd like to thank the 12 Aurora experts for joining me on this podcast. It's been a fascinating tour de force of developments from all around the world. I won't be able to do justice to try and summarize, but as a reminder, if you want to dig a bit deeper on these topics, then you can find further content to complement this podcast on our EOS platform and the Aurora website. Thanks also to our listeners for tuning into Energy Unplugged this year. I'm very honored to be the kind of curator of this podcast channel, and I think it's unique in connecting our listeners. We'd go to experts from around the world discussing the hot topics in the Energy Transition. We've got some fantastic guest booked in for the new year, so if you haven't already done so, then please do subscribe to our podcast channels, and check out future episodes at auroraer.com.