 So today we're going to talk about the enabling role of grading, has in technologies or gets, right? One of my favorite topics and their use cases in grid operations and planning. So let's start with why, right? Why they always start with why we are, you know, what's the problem and why we want to consider grading has technology. Well, the power industry has changed a lot. Like if you, if you think about it from the, from the operation side, traditionally on the generation side, the only need to deal with mostly traditional generators like, you know, thermal, natural gas, nuclear or, you know, hydro, right? And load is mostly conventional load. So it's relatively easy to match the generation with the forecasted load. That's what we call in the power system industry that we match the generation schedule to the forecasted load. Now things has changed significantly. Like we add a lot more moving parts, both from the generation side, as well as from the load side, right? If you think about power industry as kind of like the three sections, generation and load on the two side and transmission kind of like a pipeline in between. Ideally the transmission system is designed for a system that has relatively stable generation and load, right? That's what happened for a long time in our power system industry. However, you can see that in recent years, both the generation side and the load side, there's some fast movement there. There are a lot of activities on the generation side. There are a lot of activities on load side as well. That makes the balancing problem much harder to do, right? Ideally you should have, you know, you should change your middle pipeline to match the quick movement from the load side and the generation side. However, you know, you cannot just like plugging, you know, or change your transmission line very quickly. That's where the problem occurred, right? If you don't have the right location, if you don't design your transmission system for the right location to handle the right capacity, injecting to the grid and withdraw from the grid, you will have a congestion problem or you have an overload problem, right? That's what you can see from the total day had market congestion costs for all the RTOs from 2016 and to all the way to 2022. You can clearly see that, especially things from 2020. The total congestion has increased a lot because of a lot of the renewables are trying to integrate into the system. You also have a lot of retirement scheduled where already happened in the system, right? That costs a lot of challenges in the operations, the real-time operation. On the planning side, however, things are not getting easier. Actually it's more challenging, right? Because the planners today, they have a lot of goals to fulfill, not only building the transmission line, but they also need to consider all these different goals in their transmission process. And on top of that, we also have a large amount of renewable generation that tries to get into the grid, right? To connect into the grid. As you can see here, the Miso Interconnection Cube, they have close to 200 gigawatts of renewable projects in their cube. And you can clearly see that the number is not getting lower, right? So what we can expect is that, you know, both the average time until project commercial operating data is going to increase, you know, going forward. And also you can expect a more expensive network upgrade cost. And that's actually what happened, right? And the U.S., according to a DOE study, U.S. will need 60% additional transmission capacity by 2030, right? And that's the challenge. I'll give you some numbers. It takes an average about eight to 10 years to build a high voltage transmission line, right? And we're already 2023. You know, it's only seven years. You know, not enough time, right? So if you're, if you're familiar with mathematical programming, whenever a constraint cannot hold, right? If you're planning constraint that you want to avoid a feasibility issue, what do you do? You add something called a slack variable into your constraint to make itself, right? So the grid enhancing technology here is my definition of the slack variable in this transmission system. It actually bridge the transmission gap in a much quicker and more cost effective way to resolve or at least defer the transmission needs while you're building and waiting for the more transmission line to be built. Eventually you will need more transmission lines to be built, but during the process, the grid enhancing technology is a great tool to bridge that capacity again. And even, even better, like in, in, in mathematical programs, you add a slack variable, usually you will add a penalty into your objective function, make your objective function much more expensive. However, here it's the other way, right? You actually make your total cost much cheaper if you do it in the right way. So what grid enhancing technologies are we talking about here? I'm mainly focused on three of them. First is called dynamic line rating. As you can tell from the name, dynamic line rating is that you can use either a software based solution or hardware based solution to dynamically calculate the rating of the line based on real time condition, right? It can also predict the near term, you know, rating by incorporating the weather forecast into the calculation algorithms. And that's very important because, you know, all the ISOs, they run a energy market and the energy market always look ahead, right? Energy market is different from EMS, which is the status of your current system status, right? Energy market on the other side always look ahead. For example, the generation schedule now is actually determined approximately 7.5 minutes ago in California ISOs market, right? If you consider the generation commitment status is actually even further back about 37.5 minutes ago. So the market is always looking ahead. So having that near term rating prediction is actually super, super important. Another good thing about dynamic line rating is that it collects and analyze the grid data in real time. And this data can actually be used by our, you know, asset management or long term planning for their risk assessment or their, you know, granular, more granular rating determination in their planning process. So this is dynamic line rating. Advanced power flow control or APFC is another type of grid enhancing technology that, that mainly aims to reroute power flow to some of the underutilized lines using, you know, either phase shifting devices or impedance control devices on the line, right? Because otherwise you cannot really control the flow. It just, you know, follows whatever the least impedance path in the AC system, right? But the power flow, the advanced power flow control or APFC actually helps you to do that. One of the, the advantage of using or, you know, considering APFC in the system is that it can help you maximize your transfer capability by kind of equalizing the impedance across the parallel path. Imagine if you have a parallel path meaning that you have like more than one lines connecting two zones. If like one line have, you know, a lower or higher impedance, then naturally the line will going to carry more or less flow, right? Creating the, imbalancing the system by equalizing the impedance, you can actually maximize the transfer capability between two zones or two areas. And it can also potentially assist the system oscillation damping like the trans instability part if it implemented strategically, right? Especially after some major contingencies. So this is the use case, some of the use case for the APFC. The topology optimization is kind of similar to advanced power flow controlling in the sense that it also reroutes power flow to other lines in the system. However, it uses a different technology. Instead of changing the impedance or the face angle on the line, it actually changed your topology. Remember what I said that you have the middle pipeline that is very hard to change. The topology optimization is actually trying to help you with that, you know, one of some of the use cases, you know, it can open, you know, or switching or switch out some of the lines based on the real time needs, or it can also change the bus configuration at your substation to dynamically, you know, changing your, your, you know, topologies to accommodate real time operations. And of course, all of these three technologies add flexibility to meet operations and planning needs. Let's talk about some of the common line methodologies if you're not, line rating methodologies if you're not already familiar with that. So we have a spectrum of the rating methodologies rating methodologies all the way from the most conservative, which is called the static rating. Basically, we assume that one rating across the year, right, based on some very conservative ambient condition. For example, you know, during the summer time, we consider like 120 degree F or a 50 degree C, you know, as the ambient degree, but most of the time you don't reach 50 degree C right during the summer. Hopefully not a bay area, not even in Sacramento area actually. Then you have seasonal rating. Seasonal rating is actually used most commonly in today's ISOs and the utility. Typically, we have two seasons, one for summer and one for winter. And for each season, we have the normal and emergency rating, right? The normal rating is for M minus zero, meaning that the overload is there without a contingency, right? A contingency is something that, you know, the line goes out or generation goes out without plan. That's what we call contingency in the power industry. And we also have emergency rating. Emergency rating is used for evaluating power flow post contingency, right? If you have something unplanned happen in a system, then for a short duration, typically 30 minutes, sometimes four hours depending on how much the emergency rating is good for, we use emergency rating to evaluate that post contingency power, right? And moving to the more dynamic side, we have something called the NBN adjusted rating or AAR where you use the temperatures, maybe solar irradiations to calculate your line rating. And this is actually what's required by fur colder 881. So all the utilities need to implement AARs by 2025, I believe, to consider the NBN conditions and possibly solar irradiation because it really doesn't make sense to assume there are solar irradiations during the midnight because there's no solar, right? There's no solar. So that's what NBN adjusted rating is for. Dynamic line rating is very similar to NBN adjusted line rating. It's just more considered a wider range of weather and line specific factors. For example, like what additional limiting column and could be on the line, right? That's something that can be considered in dynamic line rating. And both the AAR and DLR falls into a category of weather adjusted line rating or wallar. You know, later on, if I use wallar, I mean either AAR or DLR, right? So this is the spectrum of the line rating that is commonly used in operations. How they're used in, like I said, in operations, you know, by default, you use seasonal ratings for operations planning studies and engineering is going to use those ratings in their study cases. However, if in real time, the engineers and operators see the needs, they, most of them have options to switch to a temperature adjusted radar in real time, right? What my experience in the company that I work for is that look at the temperature forecast today. Okay. The temperature forecast is 80 degree or 85 degree like the peak. However, we know that the line rating in their rating assumptions, they use 50 degrees. There's never going to be there or 120 degree Fahrenheit. Right? So they will develop those temperatures just rating usually at either five degrees every five degrees for every 10 degrees and they provide a rating there for the operators use when they need it. In planning, most of the ISO and the utilities today, they still use seasonal rating. Some of them use, even use the static rating. That's probably because, you know, they don't observe a lot of congestion in their system. So they don't feel the needs of using a seasonal rating or more dynamic rating. But, you know, if they see overload, congestions more frequently, they should be considering those, you know, more dynamic rating and they would. The dynamic rating, the dynamic line rating can benefit the grid in many ways. I already talked about some of the benefits here in my previous slides, but I want to highlight one thing that is, you know, it helps you that using a dynamic line rating actually helps you identify the limiting factors of your transmission line, because not all the transmission line are limiting by the conductors, which the dynamic line rating is able to help. Right? However, if you have, if you use a static rating or a seasonal rating that is always lower than your next limiting element, then you're not going to see your next limiting element, right? But once you apply the dynamic line rating, it actually tells you how much the conductor is good for for each section. Now you have the opportunity to see what the transmission line is really limiting, right? So that you, you know what to invest if you need to make a case. And most of the time upgrading a breaker or a CT, those can be the limiting element is much cheaper than building an additional transmission line. So that actually enable you to have more visibility of your transmission asset into your system and it adds more flexibility right in operations as well and provide more valuable data for long-term planning use, which I already talked about in a period of time. So I talk all these good things about dynamic line ratings, right? You know, and I want to show you a case study that we recently completed on, you know, WBCC 10K bus synthetic case. So this is the network data. We have a thousand, but with 10,000 buses, you know, almost 24, 2500 generators and we have all these branches and minus one contingencies. So on a very high level, what we do is we run a DC power flow and a full contingency, full DC contingency analysis for all the 87, 84 hourly cases of the year. That year that we use happened to be a leap year. Otherwise this should be 87 60, right? You can tell it's 2016 data is what we use. So we, we provide, we do the, the, the, the hourly generation, the renewable generation pattern and hourly load is part of the case package. However, we select, we need, we, we, we, we, for first of all, we run the initial DC power flow and contingency analysis, right? For every hours of the system, every hour of the year. And then we identify 25 most severely loaded line in the case and we applied the weather information. We got the weather information for those lines, including ambient temperature, wind speed, when direction, solar radiation and data time to get, you know, elevation as well. And then we applied a calculator that we developed based on the IEEE 738 2012, which is the standard for calculating overhead transmission line rating, right? So basically we use the steady state heat balance equation to calculate the weather adjusted rating for those 25, 25 lines. And then we're plugging the new rating into the system and rerun the hourly cases with the contingency and we generate some results. Actually shows some very promising results by applying the weather adjusted line rating. And here are some of the results that you can see. This is one of the lines that we picked here. The static rating of the line is the orange line, right? You know, slightly above 300 main line. And if you don't apply any cap, I'm going to talk about the cap later on, but if you don't apply any cap, these are the hourly reading that you can get. Some of them are really high. It's more than 200%, right? But in reality, you're likely not going to get like 200% rating increase because you have, like I said, you have other limiting element in the system. So in this study, we applied a rating cap at 30% higher. That's the 1.3 AAR cap that we applied there. But you can tell that consistently whether weather adjusted line rating exceed the static rating, maybe some of the time it drops a slightly below, but this is good information, right? As a utility, as a transmission line owner, you would rather know that during this time of the day, this time of the hour, you got line ratings actually lower than what you planned for. Then later on, you know, your line got burned or the, you know, got damaged for, you know, carrying too much hardware moving to the right, you have the duration curve here. You see that among the 25 lines that we selected here, the best line at 99.2% of the time of the year, the calculated, the weather calculator rating is actually above the static rating. Even the worst one is 76% right? Which is still majority of the time of the year. And like I said, for those durations where the rating is lower than static rating one, it's good information for the transmission owner to know. Second, if it has happened too frequently, then the transmission owners will probably look into their rating methodology and assumptions and trying to accommodate that and do some collaborations, right? But the bottom line is, you know, applying a weather-adjusted line rating is, you know, most likely it will give you additional capacities on your line. Some more results, you know, the weather-adjusted line rating is actually very effective in reducing or even eliminating the overload. Like for the 10 to 20% overloaded category, like in the base case, reference case, where no adjusted rating is made, you see about, you know, 8,000 accumulated hour overload in the base case. However, the number reduced to about 5,000, you know, for the weather-adjusted rating case with cat. You know, if you remove that 1.3 cat, right? That's, it's going to help further. It's reduced to, you know, you know, less than 3,000 accumulated, accumulated hour. And, you know, for the, you know, more, more, more severely overloaded line, actually it helps even more. Like some of them shows like more than 80% reduction in overload or completely eliminating the overload. On the right side, it tells you at each hour of the day, right, how the weather-adjusted line rating is compared to the base case, right? In the base case, you probably cannot see the number very clearly, but that's fine. All you can tell, all you need to know is this is much brainer, right? The brainer is always better, right? But I'm going to tell you the number, right? The number is, you know, in this heat map, the 27% is the worst average overload and happened during, sometimes in January or more, right? In this sensitive case, it doesn't mean that it's going to be in the case in real world, but in this sensitive case, that's the case. However, after applying the weather-adjusted line rating, that number reduced from 27% to about 10%. That's a huge increase, right? And we also evaluated all the different factors, the weather factors, and how to see how they can implement, how they impact the line rating. Actually, you know, the temperature, as you can tell, right? You know, you have a lower temperature, the heat is going to be, you know, pulled out from the conductor much quickly so that naturally you have a lower, you have a higher rating when your ambient temperature is lower. Wind speed is different, right? If you don't have any wind, it takes longer time to decimate the heat from the conductor. However, if you have, you know, higher wind speed than, you know, the heat is going to be bringing away from the conductor much quickly. That's why you see a higher wind-adjusted rating. The degree is actually the angle between the wind and your conductor axis, right? When you have a perpendicular direction between your wind and your conductor axis, that's when the wind is most effective, right? That's why you can tell when the degree is 90 degree, so the rating is the highest, right? By, you know, fixing everything else. And the solar radiation is the same thing, right? If you have more solar, you will see a lower line rating. However, the effect is not that much. There are still some challenges implementing a full kind of DLR or weather-adjusted line rating in today's operations, right? And I'm going to, you know, these are some of the challenges that I can see based on my experience and also some of the solutions that I offer here. First is rating uncertainties and volatility, right? Like I said, the binding schedule is always happening before the actual dispatch schedule, like 7.5 minutes and 35 minutes I talked about before, right? So if you look ahead and when you calculate the binding interval, the dispatch interval, say the rating is 500, but suddenly during the seven minute or 30 minutes time duration, wind stop blowing or something happened, then you may have a different rating, right? How to incorporate the rating difference into this real-time operation, rating calculation, marketing, you know, scheduling is actually a challenge now, right? And also the market is running continuously, meaning that it keep looking ahead, right? Like, you know, a couple of hours, four and a half hours or three and a half hours, things like that and keep calculating the ratings. However, the weather forecast can change across different runs and give you a different rating every time you run, right? So the rating uncertainties and volatilities is one of the challenges. The solution is simple, right? Solution, well, not very simple, but we made very big four. Improve your forecast algorithm, right? That's something that you can work on. Improve your forecast algorithm and incorporate a risk-based buffer. You don't have to adjust for every difference, small difference, right? You only adjust if the difference is large enough. And if you have a difference that's too large, maybe consider using a cap, right? Don't use that. Don't use that very extreme rating that is calculated by the real-time calculation. And data management is another challenging issue, right? You know, in grid operations, we have all different grid applications like SCADA that sends the data back from the field and you have EMS systems, data estimators, OMS is your all-teach management system and market engine, right? All the systems kind of connect one way or another together. So apply a rating. You need to make sure the data is, you know, flowing very smoothly across these different applications because otherwise it could create some problems. So the solution is to establish and centralize the rating database with rating priorities. What is the most important rating, right? For example, the operator overrides is probably the highest priority. And then, you know, the next priority is the, you know, good sensor data that come back from the field. And next may be your seasonal rating. And next may be your, you know, static rating, I'd say. I'd just give you an example and adopt a, you know, a standard protocols between community, you know, different, for communication between different systems is very, very important. On the policy front, I'm not going to talk a lot because Julia is going to do a deep dive, but lack of incentive is another thing, right? The utilities, the TOs, they have incentive to build new lines because they can put it into a great, great base. However, for weather adjusted line rating, that's not very straightforward at this time. And the solution is, you know, to provide more effective incentives and mechanisms for utilities to consider rating enhancing technologies. What about using more granular rating in planning? That's a challenging topic. But instead of, you know, go directly to our rating, hourly rating for the entire year, we can do baby steps, right? Right now we do like, you know, some utilities use static rating, some utilities use two seasonal rating. How about we look at the data history, do some advanced analysis and change rating to maybe a monthly rating or day and night rating, right? That itself is a good improvement. For example, if you look at the data here, like, you know, maybe you can use this red rating here for January. And for February to April, you can use even higher rating than your 30% cap, right? You know, for summertime, you know, you can use a lower rating. But as soon as you pass that summer, getting into October timeframe, you can slightly use your, you know, you increase your rating to a higher number. So this is something that you should consider in long-term planning. And the best way to do this is to use the real-time data that you collected from your sensor that installed on your line. So let's do some mentor exercise here. Okay. So this is two areas, right? One is a gen hub. The other is load center, right? You send power from the gen hub to load center. The solution is, the task is that you need to find the pre-contingency total transfer capability, like how much power flow you can transfer from your generation side to load side. This is actually operation 101. If you work for a utility or ISM, right? So you need to, remember, you need to consider a contingency. You always need to make sure the MIS-1, right? So this MIS-1 is losing one of the lines. You still, after you're losing one of the lines, you still need to make sure the remaining line, power flow on the remaining line is still within its emergency limit, which is 1200 megawatt. And the solution for this one, I already give you to 1600 megawatt pre-contingency, right? Let's see how APFC and TPO may increase this number. So if you use APFC, you know, it could be a power, you know, power electronics devices that's more advanced or it could be a simple, you know, a serious reactor or serious capacitor and the like, right? But if you can do that, you have the potential to increase your pre-contingency TTC to greater than 600 megawatt. Because once you, you know, for example, once you lose that contingency line, you can quickly insert a larger impedance, like serious reactor, larger impedance to increase the impedance of the line so that it'll, you know, reroute the power flow of that line to different lines in the system, right? That's one way you can consider TTCs. Sorry, you can consider APFCs into a system to increase your TTC. The topology optimization is similar, right? Imagine you have a different, but smaller path in your system. That's more limiting, right? It's like the smaller path, you know, it's only good for maybe a couple hundred megawatt or 150 kV length. However, you still need to make sure that, you know, the system is minus one stable. So if you lose this line, there's no overload on this line, right? If you don't open any line, then this path will be your limiting path. However, if you can, you know, somehow open somewhere in between, you still have all the load connected, some load of maybe radio, but you still have the, you know, all the load connected. However, in this case, you will, you know, drastically increase your total pre-contingency TTC from 840 megawatt to 1600 megawatt. I'm not going to go to the details. You all have the slides later on. You can look at my notes. But this is how the APFC and TPO can potentially benefit the system. This is another case, right? This is something that I talked about earlier. If you have a parallel path with, you know, different impedance, then one line could carry more flow than the other. When you calculate your transfer limit, the, you know, the, the most limiting line, the most limiting line could be limiting your, your transfer capability. However, if you can balancing the, if you can balance the impedance, the, the parallel path, then you have the opportunity to further increase your transfer capability. The GET solution can also be combined and supercharge each other, right? Each of them is, is effective. But when you put them together, it actually supercharge each other. Look at this case, right? Previously, you have a, you know, new bus where you connect a new wind generator. But, you know, in order to protect for that M minus one contingency, now you have a overload on the two lines nearby, right? And the traditional solution, you may always, you know, build another transmission line between bus one and two or bus three, but that's, you know, first of all, very expensive. Second, it's going to take a long time. What you can consider is, you know, install, maybe consider install a powerful controlling devices on this, you know, line between bus one and bus two. That by changing the impedance or the phase angle on that line, it can shift the power flow from, you know, this line to somewhere else, and hopefully that doesn't cost a different overload, right? And this line seems to be located in the high wing area, otherwise you wouldn't put a wind there, right? Since it's located in the highway area, this could be a AAR or DLR candidate. You just need to do a study and see how high wind is going to help you with your line ratings. Right? I'm not going to spend a lot of time on this, I'm already over time, but there are several highlights I want to make sure that I hit here is that for operations, it's really important to study before implementing, because some of this technologies will actually have some, you know, system impact, stability impact or protection impact. You need to make sure that you understand the system impact before you implemented them. During the planning, it's important to consider these technologies in planning, not to the point that you need to predict the exact hour and minute when to use it in operations, but to give operations more tools in their toolbox that when they need to use it, they can find it in their toolbox. That's really important. We talked about GATS, right? GATS is cost effective and its speedy response to respond to our increasing demand for transmission and it can potentially accommodate more renewables. GATS benefit can be locational and time-dependent. So leveraging insights, leveraging insights from the data analytics is very important to give you the best value of the GATS. Strategically combining GATS solutions is going to supercharge each other and give you more value and holistic planning approach that consider both GATS and the traditional solution is going to optimize the value overall. Finally, forward thinking regulations and, you know, incentivizations is pivotal in, you know, catalyzing skilled options of GATS, which Julia is going to cover in more detail. All right. I think that's the end. If you have any questions, feel free to reach out and if you have any like partnership or anything you want to talk to me, feel free as well. Thank you. Hi everyone, I'm Julia Stalker. I'm the executive director of the WAC Coalition and I'm going to talk about the policy puzzle behind the technical puzzle that you just heard about. The WAC Coalition is a trade association representing the three technologies that Okwai talked about. We're advocating for wide deployment of those technologies, which is not currently happening in the United States for reasons way hinted at and we'll get into in more depth. Our members are technology companies, renewable energy developers. You probably recognize some names like Invenergy or EDF renewables. Also AES, utility and developer, Vermont Electric Power Company, which owns the transmission system in Vermont and HACI is a clean energy investment group. So these are all entities that want to see more efficiency, more capacity out of the current grid and the future grid as well. But the question is, why did this group have to come together to advocate for these technologies that in the previous presentation you saw have a lot of value. So here's an example. The US did start pilots for DLR and discussions for DLR back in the early 2000s, even late 90s. But abroad, Belgium started even earlier and had wide deployment of DLR starting in 2012. And just one example of the benefits of that deployment is that in one day they saved $500,000. It might have been yours in redispatch costs, which are their equivalent of congestion costs. So $500,000 in one day since 2012, that's piled up. In Slovenia in 2013 they started deploying DLR and you can see that the value of DLR is not just in the basic grid configuration, but in contingency scenarios you see even more DLR value or at least number of events where DLR is useful. And in advanced powerful control you see the same thing that one story of APFC was that they were looking at rebuilding a line in a contingency situation to address a contingency and that APFC was a much better value. They put that in instead. It was never used, but it still saved a lot of money because the line would have otherwise had to be built. Germany, Uruguay, other countries are using DLR widely. In the United States the first market integrated deployment was in Pennsylvania in 2022. Pretty recently the use case here is incredible. Instead of a $50 million line rebuilds they did a $250,000 dynamic line rating installation and it saves $23 million a year in grid congestion. So the savings pilot fest we talk about payback periods of between two years or yeah, six months and two years usually for grid enhancing technologies. Obviously this one pays for itself much faster in Pennsylvania but this is the first market integrated deployment and as far as I know the only one still in the United States though other utilities are looking to catch up maybe a yes soon. So this is the problem. We're not seeing adoption of gets. So why do transmission owning utilities make the choices they make around technology, investment, etc. Policy work could focus on anything on this list right federal laws the energy federal energy regulatory commission FERC responds to federal laws and issues orders. NERC often responds to FERC orders and issues mandatory standards RTOs do transmission planning and set tariffs state laws impact utility planning public utility commissions have oversight over transmission planning. All these things are in the mix but as we indicated the the last big piece of the puzzle is money and where are the utilities expecting to make their returns? Their business and I did put a little asterisk here that this is all applying to investor owned utilities and there are many models in the United States but but financial incentives drive a lot of decisions and prioritization at utilities as well. So the other angle on that is that all regulation is incentive regulation your the utilities are going to be making decisions based on what gives their business longevity and profitability so even if we're talking about complying with FERC orders all regulation is incentive regulation to some people so Alfred Khan is a bit of a legend of the utility regulation world. All right. So what is their business model? Generally, we're looking at a cost of service business model. Stop me if any of this is totally unfamiliar but the utilities make a rate of return say 10% on their rate base plus their expenses that's their revenue requirement. So the rate base is basically that the transmission infrastructure that they own the value of that infrastructure that they own and built. So if their rate base is usually based on building hundred million dollar lines when you talk about $250,000 DLR deployment on top of that line if you could avoid that big expense well, that big expense is your bottom line. So there's there's a really perverse incentive there for the transmission only utilities. That's not to say that they wouldn't do it if it was trivial to do truly trivial but it does take those upgrades that we talked about in his presentation. So it's not automatic. It does take work. So illustrative. Example to pull in some other technologies like high performance conductors were in a regional transmission line. So business as usual is that a utility does asset replacement. They do local upgrades within their territory. It's very simple to rate based those upgrades and the regulators have been looking at the same proposals for decades and decades. Now on the grid enhancing technology side you have lower upfront costs and you might need some innovation and your modeling and your operations. And it has a little impact on the utility rate based so the utilities are essentially incentivized to tell their regulator you know there's actually this is going to be difficult. It's not going to be effective. We have other limiting elements on the lines. So the utility is not going to bring that to their regulator with a lot of enthusiasm. And on the other side of business as usual you have a higher upfront cost projects but potentially higher net benefits. So if you're talking about reconductoring a line with a high performance conductor that doesn't have a steel core. It has a composite core. It's stronger. It doesn't sag. It can handle higher temperatures. That's a higher upfront cost for the rate payer and the regulator might think are you gold plating this project? Do you actually need that? Higher performance conductor and with an inter regional transmission line similarly. Maybe you can share power you can get more capacity. You can address reliability concerns with inter regional lines but you have to allocate the cost between different groups of rate payers so we end up stuck at business as usual and it's hard for you know regulators have to push for both gets and these more complicated solutions and you want utilities pushing for those as well. So that's the policy challenge at its core and this is restating some of what we already said we need transmission capacity yesterday we can't be stuck at business as usual where some examples from developers that it was going to take four years just a schedule and outage to begin constructing gets you often don't need an outage or you need a very short outage to make that upgrade or maybe another example seven years to complete an upgrade interconnection costs are routinely hundred million dollars plus for projects or clusters and that's not feasible that's that's killing projects also doing things the traditional way is getting harder because there's supply chains for transformers and high voltage DC line. You better be planning many years and in advance plus you have to site permit and finance the line and congestion costs which we have on his early slide are growing very quickly so we need that transmission capacity so what what would an incentive for gets look like there are a few models in the UK the and this is actually evolving in the UK so this is going to be out of date for a while but or very soon but in the UK there's a baseline of performance and incentives are granted based on six categories and they include also potentially penalties there's also an innovation fund to de-risk the deployment of grid enhancing technologies in Australia they do it a little differently they there are two factors that help them select gets projects one is when you are investing in transmission you have to show a deep evaluation of multiple options whereas if you look at how Kaiso evaluates the different options not we love Kaiso but there's not very in-depth when they propose a transmission upgrade but in Australia is in-depth and that does lead to lower cost or maximum economic benefit projects being selected and then there's also a network capacity incentive where you can earn an adder on your ROE essentially for increasing the performance of your network in the US the Watt coalition has proposed a shared savings incentive to FERC which essentially says okay if you can address $23 million of congestion with a really low-cost project let's reward the utility for identifying that project and developing a solution and let's also make sure that most of the benefits are still going back to the rate payers so that shared savings incentive has been vetted at FERC through a workshop a technical conference but it's not yet notice of proposed rulemaking so a ways to go for that to become lava on the other side or not policy there are requirements and these have moved forward at FERC so if we think of all regulations incentive regulation this is still in a sense an incentive but FERC order number 2023 which made new rules about generator interconnection required transmission owners and RTOs to consider grid-enhancing technologies in their interconnection processes there's a notice of proposed rulemaking for transmission planning that does a similar integration for gets into those processes order 881 required utilities to use ambient-adjusted ratings on all of their lines and required the RTOs to prepare to accept dynamic line ratings at 15-minute intervals so that means if a utility wants to use DLR after July 2025 and they're in an RTO they should be able to which another technical leap there for the United States then there could be a requirement to deploy gets under certain conditions so say you have you know a huge amount of congestion cost on a line and it's it's historic and is projected there there could be a threshold that says okay if you see two million dollars of congestion on this line going forward you should deploy DLR and reduce that congestion somewhat or if you're not in an RTO and trans congestion costs are not transparently reported then it could be based on the hours the line is constrained or something like that there also federal grants and subsidies that utilities especially nonprofit utilities can use to lower the upfront costs of deploying these tools that's an overview of the policy landscape but we have seven minutes for questions and thus there are a bunch of slides in the appendix for a little more information about the technologies and the reasons we need them okay thank you first of all thanks both super interesting I had a question that we were sure about kind of DLRs or I guess well first DLRs but kind of like would you maybe try a sense of like a spatial granularity of like would be the DLR kind of it's like the one thing yeah so you have some monitors sensor or something you know is it for every line or just just put one in like a model or a model or anything sir how does it work it depends on the line that's the full answer if the line changes structure many times then you need more sensors online there just to capture that wind speed and directions but if you have a relatively short line that doesn't change like the you know the the turn of the line doesn't change that much then that's your time and there are different methodologies for DLR so you could have a sensor on the line you could have a sensor looking at the line from the transmission tower there's a company that uses fiber optic cables strung along the line so then you have very granular measurements of the local temperature I want you for the VL are investment it's all although it's low cost but it's still need investment or it's belong to at the minute in this cost for them today's yeah that that's a challenge because I I think in the UK they've changed from yeah the ROE is both on capital expenditures and operations expenditures and so that decouples the utilities revenue from just building new things and in the United States I think often software is considered an operational expenditure which is a problem for all kinds of situations but the one thing about the federal grant programs is that they can they can apply to the staff time that it takes for training so that's that's a way that they can subsidize the operational expenditures but yeah that that first DLR deployment is more expensive because you have to upgrade your systems and train your staff what's probably the concern of the beginning perspective is that they already found though they're judging of our operation and it's and if that could have belong to the time cost and that will be much easier for you to take it or initialize so that may be a one thing the United States could have think about change some of the time rule and enable or give the time you can still do this work give the time return and can do in that that makes sense yeah good how was Pennsylvania able to come to get some like where incentives that they use that they use in other US cases or no I'd say the it's a little bit of a black box but basically when a utility has deployed gets in the United States it's because there's one ambitious engineer maybe a couple ambitious engineers hopefully their boss is also ambitious but basically it's individuals saying we have this technology let's use it let's solve this problem and I think PPL had to work with PJ I'm also to make sure that you know they could actually use the data to to change their dispatch but it yeah there was they they were absolutely non-centivized to choose that solution but they did anyways I think there's different vendors have different approaches for communicating DLR data and I think most of them are redundant somehow so you know you'd have your default LTE system and then maybe you'd also have a satellite system for backup but that's vendor by a vendor yeah and eventually we have to comply with the SIP standards and the COM standard that's you know required by nerd mm-hmm yeah I think it's up to the utility customer to tell the vendors what they need or want perfect good to then we're talking about the um planning side of it and we're already would it also apply to the protection settings and we can be like then we're changing the protection settings based on the MDM 2 or would those be just a little static that's a very good question it could right if if you anticipate the rating change a lot let's say 30 50% then yes you need to change immediately consider changing your protection setup right if your previous protection is set up based on 100 megawatt now you're constantly see 150 200 megawatt weight then yes you need to you need to cancel that last question and then what about for transformers does that are they similarly affected by sort of higher wind speed or are you driving them a lot harder to implement to you know I don't think transformer is um is heavily impacted by wind speed however I've also seen um vendors talking about like dynamic transfer transformer rating uh they might have different set of uh you know measures other than the you know wind direction and the wind speed same answer I've heard of it but I don't know how it works because you know it's it's very short the city and sub-stations not running along right long line okay thanks everyone