Hi, good morning everybody. Welcome to the webinar. I'm just going to give it another minute or two because I can see that people are still joining. But just to let you know you are in the right place and we'll we'll get started in a couple of minutes. OK. I think we can start. Good morning, everybody. I'm Sam Hollister and welcome to today's webinar where we're going to be looking at the GB power market updates and focusing on what's next for Bez and long duration storage. I'm also going to be looking a little bit about zonal pricing and some of the developments in the UK market. I am joined by a number of colleagues who are going to take us through this morning. We have Gapo Ruperi who is a senior consultant in LCP Delta in the modelling team, Joe Wilson who is also a consultant in the in the team myself, I am the head of the UK market strategy for LCP Delta and Chris Matson, who is a partner in our power modelling team. So just a few things before we get started today. You should be able to see a few kind of ways to interact with us on the on the screen in front of you, there is AQ and a box that we will be live throughout. So please do drop in your questions as they come to you. We've got a bit of time set aside at the end to to pick up those questions. Anything that we don't pick up in the section, we will we'll have follow up in in in writing. So please do kind of keep those questions coming throughout the session. There's also a number of materials that you can download that are available on our portal. So you can see some of our latest research. Those are around best degradation. There's also a full report on our Sillery Services markets in the GB, a link to our newsletter sign up. And also if anyone would like to book a demo of our store cost products that is kind of driving a lot of the results that we're going through today, then please do. Obviously the purpose of today is to give you guys as much information as we can, but very, very happy to kind of pick that up separately as well and take people through some of them, some of the offerings of LCP Delta. OK. Just a very quick one on who LCP are. Obviously those of you that have joined have hopefully engaged with us before, but those of you that haven't, LCP Delta is an energy transition advisory firm. The people you go in front of you today are very much focused on our power and our power modelling and power research teams. But we also have a number of teams looking at customers and demand or networks or flexibility markets and also on investment and commercial. So almost we're an energy advisory firm that can help you no matter what your question is. And that's through a range of research products or tech and data products, but also free consulting services. So please do kind of reach out and we'd love to kind of help you along your your journey through the energy transition. OK. So just to be clear about what we're doing today, I'm soon going to hand across to Joe who's going to take you through our power market outlook and focus on on that for 10 or so minutes. And then to careful who has been leading a lot of our work on long duration energy storage. People may be aware that we delivered the original piece of analysis for the UK government that supported a lot of the capital floor proposals that's been coming out from from Desness and Ofgem. So we'll take people for a little bit of RM analysis in the way that we've been supporting that kind of very interesting development in the sector. And then finally, probably no webinar that anyone has attended in the last six months or so hasn't touched on zonal pricing. So we're going to make sure that we keep up that that tradition. And Chris, he's going to talk us through zonal pricing and some of the kind of the the work that we've been doing again for Desner's, but also for a number of clients and helping them understand kind of the impacts of what's been happening for or what the potential impacts are on zonal pricing. So that's the set up for the day. We should be about just under an hour. And as I said, we've set aside some time for people's questions. So please do make sure that you're kind of populating those. And I'll come back on at the end of the session to to help facilitate those questions and hopefully put the the free gentleman in front of you under a bit of pressure to answer some of your questions. So on that I will pass across to Joe. He's going to take us through the 1st agenda. Thanks, Joe. Great. Thanks, Sam. So we update our power market outlook on a quarterly basis and these scenarios are used across a range of the consulting work that we do. The scenarios are also available through our store cast platform which can be seen on screen and this platform allows users to run bespoke, bespoke storage assets through our trusted modeling framework. Users of the site can set a wide range of customizable site specific inputs such as efficiency, location, cycling limits and any Co location with wind or solar. We are also now releasing the functionality to model long duration storage assets through the site and Gopal will come on to this in more detail later. Now LCP Delta have modeled the energy transition for over 10 years working closely with the UK government and other public bodies like NISO. Our modeling is all built in house and this gives us the flexibility to constantly update our modeling in response to any market changes. Our Envision modeling framework takes in a wide range of inputs including commodity prices, demand profiles and historical weather data to simulate the future power market on 1/2 hourly granularity over the next 30 years. Using a fundamentals based approach. We use a large number of stochastic simulations to capture variations in, for example, wind and demand profiles, and we use granular plant level operating parameters to provide accurate and detailed insights. We can then use the outputs from our modeling for a range of applications from supporting on investments to evaluating policy decisions. I'm now going to talk briefly through some of the specific assumptions that go into our latest modeling, followed by some of the key outputs with a focus on those concerning batteries in particular. So First off, we expect total electricity demand to significantly increase in the long term, with growth of around 100% by 2050, and this is driven by a combination of different factors. The drive to decarbonise heat and transports are projected to lead to significant demand growth post 2030 due to EV and heat pump uptake. Data centres are also a key driver of increased demand due to increased data processing requirements and the spread of artificial intelligence. Moving on now to our capacity mix. There will be significant renewable deployment in the coming years as the government attempts to decarbonise the power sector. And whilst we do forecast the government falling short of their targets, there will still be very large growth, in particular in wind and solar. Unabated gas capacity will gradually come off the system and be replaced with low carbon dispatchable capacity such as hydrogen to power and carbon capture and storage. Electricity storage technologies will also play a huge role in the renewable transition. This is likely to include a mix of Bez assets between 2:00 and 8:00 hours in duration along with pumped hydro storage and some vehicle to grid as well. Other new flexible technologies will emerge as scale as the system decarbonises. These will include electrolysis and demand side flexibility, which will be very important in helping address renewable variability. Interconnection capacity to the rest of Europe is also expected to increase, allowing greater flexibility between these connected markets and will result in a less volatile price overall. We have updated our storage capacity figures this quarter following the recent capacity market auctions. Historically, Bez assets have broadly fulfilled their capacity market obligations. However, the amount of battery capacity that has cleared in recent auctions has increased sharply from a few years ago, meaning that around 25 gigawatts of battery capacity would be operational by 2028 if all of these assets fulfilled their obligations, up from just around 5 1/2 gigawatts currently. Based on conversations with developers and others involved in the supply chain, we forecast a lower build out of Bez in the short term with higher termination rates and delays expected. This still leads to about 18 gigawatts of installed Bez in 2028 in our central scenario. Turning to some of the key outputs of our modeling now, here is the generation mix. In our central scenario, we expect renewable energy to dominate the future generation mix with over 80% of energy supplied by wind and solar from the mid twenty 30s onwards. This renewable generation will be supported by a combination of storage and low carbon dispatchable power to account for variability in renewable production and ensure the security of the electricity supply. The low the low carbon thermal capacity is expected to have a fairly low load factor and will make a significant proportion of its revenue through support schemes like the capacity market or dispatchable power agreements, rather than just energy markets. Storage currently makes the majority of its revenue from energy market trading and price arbitrage, buying low and selling high. Whilst opportunities to do this will increase as market volatility grows with renewable penetration, higher deployment of storage will counteract this by decreasing market spreads and cannibalizing revenues. Now I'll move on to how this renewable transition effects market prices. So in the short term, gas fired generation sets the price in most periods, meaning the electricity price is very correlated to the gas price. Prices are also well aligned to demand, with peak electricity prices generally occurring in the evening when demand is highest. In the medium term, increasing renewable penetration results in a greater proportion of demand being met by low cost production, leading to lower prices. In a large number of periods, all of the demand will be met by renewable sources, leading to very low and sometimes negative prices. In the long term, the increasing carbon price feeds through to the peak power prices and causes a slight rise in in the average prices. These peak power periods no longer, sorry, these peak price periods no longer really aligned with the demand peaks and they're more heavily driven by the renewable generation patterns now predominantly winds generation. So now moving on to some battery specifics stuff. This chart shows the average revenue over the last four years for two hour best assets in GB and this is using our Enact platforms GB best index. So assets made significant revenue in late 2021 due to tightness on the system and in 2022 due to the very high gas prices as you can see here. But since then the revenues have generally been more stable with an annualized revenue of £100 per kilowatt observed in April. As time has passed, these assets have been making a higher proportion of their revenues from energy markets rather than frequency response services. And this is because the frequency markets have become more saturated as more beds capacity has been coming online. So now moving on to how we forecast revenues to look in the future. We expect revenues to increase in the short run primarily due to rapid renewable deployment and this increases volatility and price spreads within markets. However, in the longer term, we do forecast revenues to fall slightly and this is partly due to increased deployment of storage as we assume battery CapEx falls in the long term and this leads to increased competition and cannibalization of battery revenues. In our latest quarterly update, we have decreased our gas price assumption and updated our short term best build. As previously highlighted, these have both decreased best revenues in the short term, medium term. However, in the longer term, level of best capacity is calibrated based on the required return an asset would need in order to make the decision to build. Meaning that these changes do not affect long term revenues as lower levels of battery capacity are therefore endogenously built within our model. As a result of these changes, I'm now going to hand over to Goeppel to talk through some of our analysis on long duration storage. Cool. Thanks, Trey. So I'm just going to talk through our the need, the future need for long duration storage and the value that long duration storage and can capture and through the market and as well as provide to the system. And and then how we model and long duration storage and how we can support applications to to the cap and floor scheme and supporting and renewable curves and projections and to support an application to that steam and as well as provide analysis on the overall value to the system that your project and provides. OK. So, and this chart here is just showing on the right hand side is showing the well effectively the need for full on duration storage going forwards in time. And so it's showing 2 curves and for 2023 and 2035 and, and those curves are essentially showing the distribution of, of, of shortfall in generation and excess and in, in generation and relative to demand. So what we're showing here is essentially the difference between renewable output, including inflexible base load capacity, so nuclear output and, and demand. And for for any given hour, you can see in 2023 and that that distribution tends towards there being a shortfall and additional and generation sources are required and to to meet demand on the whole say gas generation into connector imports and biomass and and other sources of generation. As you turn the clock forward to 2035 and on the Desmos is a net 0 high demand scenario and there's much more renewable capacity on the system that distribution of shortfall and access becomes much more spread out. And in 2035 in about 60% of all hours, there is an access in generation. So quite an increase from from from current levels and overall. And we, we projected that there'll be 70 Terrell hours of excess and generation and that there'll be a need of 50 gigawatts of flexible 0 carbon and capacity required and to manage bouncing and constraints on the system that that capacity has to be 0 carbon. And it can take many forms that could be forms of load shift and demand side response, electrolysis interconnection and but also, you know, forms of, of energy storage. So battery storage and, and long, long duration storage. And at the moment through through the capacity market we're currently building out predominantly short duration storage and mostly mostly 2 hour and lithium ion and battery battery storage assets. And those assets are able to build and within within MCM time scale. So within within four years, yeah, we were in the same time scales, but for some forms of longer duration energy storage aren't able and to build within those time scales, So and pump storage and for example those forms of longer duration storage and we're also not fully remunerated to the market. They provide additional value to the system and on top of an excess of just making more efficient use. Of, of of, of. Low cost and and renewable and generation and to to help incentivize the build of these longer duration forms of energy storage and Ofgem is managing the cap and floor scheme, the window 1 scheme and for for for longer duration storage and. Which we are helping to support and applications to. So our store cast platform which Joe touched on earlier and has been updated, we're able to model a longer duration forms of of electricity storage of up to 12 hours in in duration. And the key change here is allowing storage to optimise its actions over potentially multiple days and by providing greater story and greater foresight and to the prices that these and storage assets can see effectively. And these projections are fully site specific And so round trip efficiencies, technical parameters, durations are all customizable and those projections will reflect the site specific natures, locations of your projects like locational constraints, locational network charges and are all taken into account. And all of our projections through Storecast are underpinned by our and quarterly market updates. And so just an example of how long duration storage acts and within within our modelling. And so the chart on the top here shows the actions of short duration assets and long duration assets in our modelling and say columns above and the 0% line show when the asset is charging and below that 0% line show when when the asset is discharging. The two hour asset and which you can see and appears quite spiky in terms of its charge and discharge is responding to and price spikes which occur and fairly close and to RIP to territorial time. And and in comparison, the the longer duration 12 hour asset is able to capitalize on some of those and and price spikes close to real time, but will also act to flatten prices and respond to more broader trends in in price peaks and price troughs and which occur. So you can see on between days three and four in response to a period of sustained high prices and 12 hour asset is discharging and following days such into into day 4 the 12 hour asset is charging for a sustained period of time in response to a period of sustained and low prices. So what kind of value can a long duration storage asset capture and how does the the the revenue make up of of a long duration asset compared to that of a of a of a shortage duration asset. And so the chart on the left hand side here is showing for 20-30 in relation and to a two hour and bass asset and the additional increase in margin and for each additional hour of of storage in relation to that to our asset and that a longer duration and asset could capture. And again, assuming that the same technology so on, on essentially the same basis. So you can see as you move from 2:00 to 3:00 hours, there's a roughly 25% increase in, in, in, in the total gross margin of the asset and a similar increase from steps 3:00 to 4:00. But that increase will and does diminish over time. So as you get, as you move from the 7th hour of additional storage to the 8th hour of additional storage, that that increases roughly about 15%. And this reflects and and price spreads and diminishing and from from from from the first hour and from the lowest price in the day and the highest price in the day, which is obviously your your widest and price spread through to the 7th and 8th hour, which are obviously and lower your lower and price spreads. The right hand side chart just shows and as a as an overall proportion to to the total gross margin in in 20-30 and which are the key revenue streams and for two hour and 4 hour and 8 hour asset. And you can see as you shift from a short duration and two asset to a a longer duration 12 hour asset that the revenue stack and does change quite significantly. So there is a move away from now there is a more of a move to revenues been provided through capacity market due to higher and derating factors that are longer duration and can access as well as a move from move to increased returns and margins through the wholesale market which is much more which is deeper and more liquid. And then intraday and bouncing markets, those wholesale returns and those capacity market returns much more bankable and and more more reliable than those. Then you can get through intraday bouncing markets where there is a great deal of uncertainty in and the size of the bouncing market and going forward some time and whether your asset and will be utilized. There's a variety of reasons why NISO utilizes some assets over over other assets. So through our store cast platform, we can support applications to the cap and floor scheme in providing revenue curves to underpin the application to that scheme. And for the first deadline for that scheme is is the 9th of June. And so that's the deadline for applying to the window one and cap and floor scheme. Following that point in in Q 3/20/25 applicants will have to submit and detailed project costs and those will allow an Ofgem supported by National Grid to make to to undergo a cost benefit analysis and an assessment of the system value and that your asset can provide. And then in Q1 and Q2 of next year and the results of those assessments and will be will be provided and then those assessments are looking at and does that and does that project, does that form of long duration storage provide value to the system? And is there an overall benefit and an increase in the socio economic welfare and provided by that asset and that that system benefit that can take many different forms and putting long duration storage on the system and reduces an overall generation costs. And assets are more and are able to and long duration storage assets are able to utilize more efficiently and more efficiently in the low cost and renewable generation. And and and and the excesses in in that low cost and renewable generation shift it to higher price periods in the day. As you build out additional long duration storage, the need for additional renewable capacity and reduce it. So you need less and renewable capacity on the system and you don't incur that additional CapEx and you also need less peaking capacity to back up that the additional renewable capacity that would be required when, when, when the weather conditions are less favourable from for generation and from from those asset types. So key to gaining support through through the cap and floor scheme is is showing and that your asset that your form of long duration storage does provide value to the system. And we have worked with Des Ness and in concert with region previously and produced the initial report on on the benefits that long duration storage can can provide. And our modelling is in line with the approach and that Ofgem is proposing and it uses the same and key metric which is and what is the change in system cost, what is the change in the overall and socio economic welfare to the system for building out and that storage asset. And the chart on the right hand side just shows for I think it's additional and 10 gigawatts of long duration storage, how that that benefit is, is is manifested so and that benefit and takes the form of and reducing the costs of imports from mainland Europe to GB reduces CapEx and network costs. As you build out less and renewable capacity, you need to reinforce the system slightly less because you've got a lot that long duration storage in place, you reduce generation costs. As you make more efficient use of of the system and the existing and generation on that on that system, it reduces answering costs. And again you make more efficient use of of existing and capacity on the system. So using store cast and using our in house modelling suite, we can provide both and revenue curves and provide supporting system cost analysis to support the deployment of long duration storage and going forwards and and their applications to to the capital scheme. Chris, I think I'm handing over to you and to cover signal pricing. Thanks, Kate. Paul. Yeah. So I think as Sam sort of mentioned earlier, I think probably everyone's maybe sick of hearing about zonal pricing, but I thought it was worth just kind of covering where we think we're at. And I guess the, you know, how this links into the power market update that we've just been talking through and I guess our support for storage in particular. So in terms of what zonal pricing is, just a bit of background, I think everyone's probably aware it's essentially moving from a national wholesale price to zonal wholesale prices. And from a government's point of view, there's kind of two key motivations here. 1 is to provide a more accurate investment signal, so that generation and potentially even demand that can locate flexibly. So new assets are incentivized to locate in the right places to reduce the overall cost of running the system. And we're saying here that there is already a locational signal or multiple locational signals in place. We already have the tenuous regime. So through network charges, which is incentivizing those those decisions to be accurate. We also and we also have network losses that are accountable within the within people's, the whole surprise that people effectively face. And the second potential, I think the the motivation which has become even even more front and Centre is that of operational efficiency. And that's essentially ensuring that we're dispatching the most efficient sources of generation when we actually go right through from not just the wholesale market, but through the actions that National Grid also in NISO now take to, to account for constraints. I think particularly there, there are some inefficiencies in the current operation of the system due to an inability to redispatch interconnectors efficiently and potentially some inefficiencies in the ability to redispatch storage efficiently as well. I guess you know, the counter arguments to those key motivations is that you're making a pretty large change to the to the to the sort of fundamental building blocks of the of the energy market and you're doing that at a time where there's lots of investment needed. So I guess any kind of delays to investment, any increases to the cost of capital could potentially offset these these potential theoretical efficiency improvements. So in terms of then thinking about signal pricing. So I guess just in terms of the time scales, we're expecting an announcement from from government over this summer. We're understanding that the recommendations and evidence has been passed on from civil servants to ministers and the decision now lies with ministers. I guess if you're looking at an investment including storage investment that should be market, this is something that you know people are needing to take into account as the potential impacts that zonal moving, zonal pricing could have on their assets. Probably a few key uncertainties there. 1 is around the actual zonal configuration and we don't expect government to actually provide a clear defined zonal configuration. And by zonal configuration we mean how many zones and where those zones zonal boundaries are located. We expect them to provide sort of a range and some guidance over exactly what criteria will be used to assess where those where those zones will be if they do announce that they're moving to zone pricing of the summer. The zone of configuration that we've been using in our analysis with clients is consistent with the one that we used with Disney's and that's a 12 zone configuration which you see there on the left. Whether it's a whether it does end up being a 12 zone configuration or slightly fewer zones, you might get fewer zones because of concerns over liquidity of concerns over potential market powers, the ability to manipulate prices. If someone owns a large share of the generation in particular zone, for example, then there's some reasons for gun fewer zones. Although you might get more than more than 12 zones if you if you think that you're not capturing some of the key constraints on the on the network. I think we're expecting government to kind of provide a bit of a range of where they expect those to end up. And as I said, not providing the key details there. Our modelling is set up so that we can we can capture a range of different zonal configurations is something we can sensitize in any analysis. I guess depending on more your assets located, you know, relatively few zones could be be sufficient to capture the key boundaries which are relevant to your asset and the impact on the prices that you'd face. But potentially for assets located particularly in relatively constrained areas of the of the network like Northern Scotland, then those, those, you know, the precise nature of those zones and, and that sort of configuration could be quite important. The second kind of key uncertainty there is around legacy arrangements and that's obviously affecting both, well both existing assets on the system, but also potentially assets which are coming through in you know AR 7 CFD rounds and potentially AR-8 as well. So to the extent that there's any kind of compensation or grandfathering arrangements around lost revenues to those to those projects, again, there's a lot of uncertainties there around what those legacy arrangements would cover, how long they would last, which revenue streams they would be looking to compensate assets for. We've done a bit of work with consortium of renewable developers to look at those options kind of present what those I think those could actually cost to to government. But again, we're expecting, I think we're expecting quite a lot of detail or hopefully a lot of guidance from government when they do announce. And if they do announce in favour of zonal around legacy arrangements, something there's those will be very important in terms of the success of of the AR 7 CFD option, which will which we're expecting to follow after the zonal announcement. And the third one there is around the actual counterfactual. So we talk a lot about what exactly what signal pricing going to look like. I think there's also quite a lot of uncertainty around what are what the alternative would be if we if we don't go ahead with zonal pricing. So there's been, you know, governments made it clear that they would look to be reforming the national market, reforming the Tenuos regime, reforming to the extent possible the way in which Nisa is able to redispatch the redispatch assets and particularly interconnection efficiently. So I guess what you assume there is also important around around both you know, what you expect your asset to earn under a national pricing, but also what the what the delta is versus zonal pricing. So I guess in our modeling, we have we have detailed modeling of the Teneos regime. We have forecast of Teneos both under current arrangements, but also under some of the proposed reforms. And we've also been working with with with clients on potential reforms such as the optic proposals from from Scottish Power renewables. Just kind of looking to try and understand what zonal pricing, you know what impact zonal pricing will have on the revenue step. So Kirk will showed a useful kind of breakdown in one of the previous slides around what the what the revenue stack looks like and how that changes between a 2 hour duration storage asset and an 8 hour duration storage asset. So that you know movement away from you know a lot of portion of the revenues coming through commencer services and intraday and balancing and the greater amount coming from from the wholesale market and capacity markets. I guess with this kind of stepping through and sort of understanding how these sort of different revenue items change and remove the zonal pricing and how that could affect affect assets. So wholesale revenues would obviously change if it depends on your location, but essentially the wholesale price that you face would be different. If you're in a constrained zone, then those those prices could potentially be quite a bit lower. If you're in a zone which has excess generation which we expect for example Northern Scotland to be, those prices could be higher on average. If you're in a in a location like Southern England, we're expecting to be higher than generation in general than it is under under national market. So that scale of change will be quite significant. In general, we expect people talk about will it will volatility be larger under zonal pricing. Again, it's quite dependent on the zone. There is a risk that if you're in a in a zone like back again to use the example of Northern Scotland, then renewable generation is, is an excess for so long that you have very long periods of low prices, which results in less volatility. And then equally on the flip side of that, that you're in a situation in the South of England where you have long periods of of high prices. I guess worth keeping in mind that we expect the kind of national market to have relatively favorable conditions for storage in terms of the level of volatility, we have sort of a mix of low prices from renewable setting the price to higher prices from thermal setting the price. So a move to zonal pricing will not necessarily be favorable in terms of the impact on volatility, the BM. So in terms of the impact on energy actions and the balancing mechanism that would not be directly impacted. We'd expect national grids to still be doing injections in the same way that they currently do. But I guess which which currently already need to take into account constraints on the network. But they'll obviously be indirectly impacted because different things would would need to be turned up and down based on their positions would be different from the wholesale market which would be which would be under a zonal pricing regime and system actions would be greatly reduced. So those are the actions which it's currently taken by NISO in the balancing mechanism to resolve constraints, those with no longer be needed or would be greatly reduced off. If you've had some quite, you know, large zones, so relatively few zones, there would still be constraints within those zones that would need to be resolved. And there would still maybe some system actions need to be taken to account for differences between the data in position and the real time position. But the vast majority of those major system actions to account for those big constraints over the key boundaries would would be resolved in the wholesale market support under the CFD scheme. CFD scheme government already said that there'll be a zonal reference price, which means that you CFD supported assets would would still receive the same price. So they'd be topped up based on their local zonal price rather than national price, which means that the price they would be the same, but the volumes that they actually would be materially different potentially. So you know, no longer being no longer being able to be compensated for generation that you were ultimately not able to deliver due to constraints on the network and to new also we talked about. So I guess what a lot of what makes some of this analysis quite complicated is that there is a counterfactual locational signal and that's to newest those to newest signals are expected to become even more sharp than they currently are would expect to newest to and from the point of view of a generation asset to be essentially removed at least the locational signal to be removed again, if the zones are quite large, you know, there's currently 27 to newer zones. If we only had six zonal pricing zones that you might need some to newer signals within zone. But the large discrepancies between the north of Scotland and South of England would be would be should through wholesale prices will no longer need to be captured through to New York. There's a question mark of whether generators would still need to pay some sort of fixed charge across the country as a residual element. But the the mains of locations that will be removed the capacity market and ancillary services sort of similar to the balancing mechanism energy actions, you know would still have a capacity market. We still have a national capacity market, but obviously they'd be infected. You know the way in which those assets are bidding into those markets would be affected by their expectations over what they're going to earn in the in the wholesale market and therefore be impacted by by zonal pricing indirectly. And similarly for ancillary services, I kind of tried to bring that together to what that potentially means for for different types of assets in different locations. So if you kind of example assets down that rose there and then the impact that that might have if you were in a very low price zone such as N Scotland or very high price zones such as southeast of England. And some of this is as I said previously is a bit more complicated than you might think. So I think something like CFD supported renewables price is not really going to be affected during the contract. There is some merchant tails or post contract and impacts your volumes decrease quite significantly potentially if you're located in the north of Scotland, but you're also no longer going to be facing those relatively high to nuance charges would expect the overall impact to be negative, but that that loss of that of that punitive to Neos charge would would offset some of those some of those losses. I won't go through every single one in a huge amount of detail given the time, but maybe it's right going down to the the bottom row, which is sort of focus of this webinar which is on storage. I think it's quite complex and quite difficult to kind of summarize. So if you're in the north of Scotland, we expect energy spreads to decrease a bit because partly because as an entry storage asset and the current national market, there's an opportunity to essentially arbitrage between that national wholesale price and then also and then the value you can capture through those system actions at NISO takes. So which you would be removed under zonal pricing because you'd be exposed to that that kind of locational value from the outset. But again, you're, you know, to nuance charges would would would decrease sort of partly offsetting that was, you know, storage currently is is sort of punished in the north of Scotland for being through high to nuance charges and those would would decrease. So it's a bit uncertain about the impact there for a storage plant located in the South of the country, we actually expect energy spreads to slightly increase in general. So some higher, some higher sort of spiky prices. As long as it's sufficient, you know, low prices to charge the asset which we expect that there will be in most locations. And what, what it really comes down to in most of the southern southern assets, southern locations, sorry, is whether you have what, what impact on those high discharge prices that the the regime will have. And then and also you're, I guess offset again, offsetting that is the fact that there's a tenuous benefit currently for assets located in the South, which would be which would be lost. So quite a complex picture, obviously something we're now working with clients to kind of understand the impacts on their particular assets. Just a kind of quick summary of the work we've done so far and done a pricing. So we did the original study for Disney's published early last year around the overall, you know, benefits to the system of moving to zonal pricing and how you know what also looking at what you would need to believe around cost of capital increases and so forth to to wipe away those benefits. That study in the publication with SSC to look at changes to those benefits under under the updated so network plans. And as I said, we're working with consortium renewables around the the kind of potential options for legacy arrangements and how they would impact overall costs. But I guess when I guess essentially moving away from that kind of almost lobbying part to now actually helping clients understand, well, if signal pricing does go ahead, what does that actually mean for the revenues of your particular assets that they're investing in? And that's, you know increasingly scenario that the clients as you may understand are very interested in seeing. I think that's all from us. We've got a few minutes left for questions. So yeah, happy to the next time we're going to moderate, moderate those. I haven't been paying attention all the questions. Brilliant. Thank you very much, Joe Careful and Chris for taking us through that. A lot of material in there. So it won't be a surprise to for people to know there are a number of questions. We've got around about 5-10 minutes. So we'll try and pick off as many questions as we can. If we don't get to you, we will follow up. But also it has people kind of digest this or receive the, the, the slides as a follow up, which will be coming out in the next day or so. Any further questions I think I can speak on behalf of everyone speaking here. We're very happy to discuss and talk to you about the what you've had here or any follow up questions you have. It won't surprise people to know that that's the focus of quite a few of the questions are on revenues and kind of how the system is going to manage. And I think I might kind of lump a couple of questions together. And, and one thing that's kind of coming out is the kind of the, the for long duration storage, why kind of the government is needed to kind of step in and provide that kind of cap and flow mechanism. And kind of where is the kind of the future revenue chunks expected in Elders? Is it free price arbitrage? Is it capacity market? Is it any ancillary services? So perhaps that one took Apple fast off of where Elders is expected to kind of make its revenue. And then I'll probably just immediately and follow up to Chris, just to kind of that interaction between longer duration and shorter form batteries and how the kind of the market is expected to balance those. Are we expecting kind of elders to come in and remove the revenue streams for bears or are they doing different things in the market and how do we kind of see that rolling out? So yeah, perhaps to you first, where is out as much money and why the capital floor is needed? Sure. So long duration storage will principally make its money through price arbitrage through charging when the price is low, discharging when when the price is high. It will also make additional returns through and providing a source of firm capacity to the system. So and without the cap and floor scheme would be participating in in the capacity mechanism and receiving a high D rating, you know around about 90% equivalent to to thermal capacity. And that long duration storage as well will also provide other forms of ancillary and service to the system. So keeping the system stable or provide inertia and can provide and frequency response can provide and voltage support. So those are all the services that that long duration and storage can provide. And I guess what, why the cup and floor is needed is because one, some forms of long duration storage can't deploy in, in a in a short time scale, can't actually build within same time scales and, and that and, and, and, and I guess the other reason is because not all of the value at long duration storage and provides and can be monetized through through those markets. So for example, if you're building out now a 12 hour asset, you don't need as much offshore wind or onshore wind on on the system as you would otherwise need if if that storage wasn't there. You can more efficiently utilize the existing generation and on site you don't need additional peaking capacity whether it's some form of hydrogen gas turbine or unabated gas or or CCS. And because you know that long duration assets that can can output for a number of hours. So those CapEx savings and not having to deploy as much renewable capacity as much and peaking capacity and This is why essentially that capital schemes is needed. Chris, anything to add on kind of the interaction I suppose between elders and shorter duration battery storage? So scalable says long duration storage, it can be difficult to deploy, deploy can take a long time device. If it's the system that I'm always monetized, I think there is a danger and we published some analysis with consortium of those developers around the impact that it has on short duration pairs. So both both in terms of, you know, if you are, if cap and floor provides greater build out of of eight hour plus duration than you would have otherwise got because it's even if it's not a a subsidy, because it's providing providing kind of an ability for them to finance their projects more efficiently. Then that will that will cannibalize some of the revenues for the shorter 2 and 4 hour assets who don't have access to that same that same kind of scheme or revenue stabilization scheme. So there is AI think there is a danger here for shorter duration if the cup and floor scheme deploys a large amount of those sort of eight plus hour duration assets. And I think with for that reason, I know a number of storage, shorter duration storage developers are looking at options of whether they want to be I guess diversifying their portfolio into and so much longer duration assets as well. Thanks. And also just picking up a couple of questions. So yes, we will certainly be sharing the slides. We've obviously kind of provided an overview today on our approach and some of the drivers towards the revenues that people will be expecting. Obviously as a as an Organisation, we do provide clients with those revenue curves and with those projections. So we just understandably hopefully haven't put those up on the on the screen today. But we're very happy to have a have a bilateral conversation with people and, and how we can support on, on those important kind of modeling questions. And because one of the other questions is probably worth coming to you for is if people will be aware of other providers of these sorts of revenue curves. Yeah. How do we kind of how does LCP differ from from other kind of market players and in providing this type of analysis? Yeah. So I guess there are where, where there's number of providers out there. I guess there's, there's, we're saying that there's a lot of uncertainty over a lot of the assumptions have been made in this sort of analysis true from the actual underlying costs of the, of the technology that storage technologies are being deployed right through to some of those sort of obviously wider macro factors. So I think, you know, we're the conscious of fixes some divergent and views over what those, what those revenues will look like. I guess some of the advantages. Obviously we've we've worked quite closely with government for a number of years. So we've got that's the credibility and those links and sort of that kind of understanding of the direction, the policy direction and how that impacts the wider system. We've got a team of, you know, across LCP Delta, there's 120 people at LCP Delta. A lot of those are providing research on some of the demand side development. So the trends on the, you know, the roll out of heat pumps and EVs and everything else, which obviously will become an increasingly important part of the sector. How Enact platform, we're working very closely with traders and optimizers. So we're seeing how storage assets are actually being dispatched hour to hour on the ground. So we can we feed in some of those insights into our long term modelling. I think we're relatively agnostic or independent around views on different technologies. So we're not championing 1 technology over another, which other providers may have to some extent A vested interest in a particular technology. You know, if you talk about some of the sort of fundamental based analysis modelling approaches. But I think that's probably. For the last couple of minutes, probably. A too much detail, but yeah, those are some of the sort of advantages that we often point to. Excellent. Well, thanks Chris. And I think again, if anyone wants to kind of pick up any of those those points, very happy that we can we can do that. I think, you know, we're always we're increasingly kind of being asked to kind of compare with with other providers or people kind of looking at kind of your different ranges and different scenarios. Because we're aware that, you know, there's as Chris says, a lot of this is driven by assumptions and by models. So we're very keen to kind of discuss that, discuss your kind of requirements with people on that. I was about to ask a question to Joe and Gap or about how the model kind of evolves, I suppose and as the market evolves, when we see the kind of your system requirements changing for bears that they might be kind of required for the frequency response or for inertia and how kind of the market may procure those services in the future and how we pick that up. But given it's kind of two minutes to 12, I think it's probably time to stop that. I think we will be having this webinar again and make it a regular feature. So thanks to everybody who has put questions to us. Thanks in advance for for kind of engaging, engaging with this and any questions that people want to follow up on. And we'd love to chat to you about the modeling and about how we can support you in that investment or as Chris said that we have a kind of a trading platform that we use for in acts as well. I'm very happy to talk about our kind of modeling approach. There's a number of reports on your screens at the moment. That's part of our regular subscription service that people have been accessing. So those are kind of a number of free reports. I think there's also a report on there that kind of shows you all of the things that within the service. So again, very happy to kind of pick up and follow up that and see how that can support you on both your kind of revenue forecasting, but also your understanding in the market and the policy and regulations. If there are particular reports that people want us to go a little bit deeper into very happy to set up kind of conversations, whether that's because you're interested in how battery in the battery degradation report, for example, or I think the a number of other reports are available. We're very happy to, to pick that up. And there will be an e-mail after today's event that would include a contact link and also a copy of the slides. And I think all that leaves me to do is just to say thank you very much to to go power to Chris and to Joe and thank everybody for their time this morning. Have a nice have a nice day and a nice bank holiday weekend. Thanks everybody.