 I'm joined by my colleague Lee-Ang Min from Stanford Bits & Watts Initiative as your co-host for today's edition of the Digital Grid Summer Webinar Series. And we're delighted to have you all here and we're excited about our panel that we have here. Our focus this week is on customer DERs and wholesale markets. And what we'll see here is a great panel in the perspective of transmission system operators, which is a great voice to hear in the overall discussion about digital grid. So let's go ahead and get started. First, a bit of housekeeping. Everyone here is on mute and a number of you I know have been on a lot of our other series so you're familiar with this, but for those of you for whom it's your first time. The best way to participate and engage and ask questions or interject comments which we'd like you to do is via the chat feature. So if you look on the bottom of your WebEx panel, you'll see a cloud button there with a chat feature and you can go ahead and click that to submit questions or ask comments, see clarification. You can also select the Q&A function at the bottom to ask questions directly to panelists or to all the panelists or to the hosts. So that would be the second way to engage and there's also a way to select yourself to raise your hand and we can unmute you to ask a verbal question. But I think the chat or the typed in Q&A is probably preferable. And we are recording this session so your participation is your consent to be a part of this recording. And we will be posting as we have previously all of the presentations as well as the recordings on both the EPRI and Stanford Web sites and we will go over that a bit further. Okay. Stanford and EPRI are both delighted to be hosting this series. EPRI we're an independent non-for-profit organization. We do R&D across all the full spectrum of utility operations from generation, transmission, delivery and end use. And our objective is through our collaborative research to keep electricity service safe, affordable, reliable and environmentally responsible. And part of our mission involves working with experts and the best out there. And we're pleased to be working in close conjunction here with the Stanford Bits and Watts Initiative. As you see there, it's a major initiative focused on digital innovations of the grid for the 21st century. Advancing business innovation policies and particularly technologies between the customer and the grid, which is exactly what we're talking about here. The objectives of our summer webinar series are really to convene experts from multiple disciplines, from multiple industries and multiple functional areas within industries to exchange views on what a shared integrated grid represents. You see there in the graphic on the right a number of elements that constitute aspects of an integrated grid, a shared digital grid. And we've talked about this in through some of the previous discussions that we've had. One of the key gaps that we see overall as a theme is enabling data platforms to allow this seamless connectivity between customer resources and the grid. So to that end, we're seeking to understand industry requirements, technological opportunities to bridge those gaps, and to ultimately inform a research roadmap and collaborative initiative that EPRI is looking to undertake in conjunction with the industry as a whole, informed by these discussions. So again, there are different ways of defining what an integrated grid is, but for our purposes in particular and as a theme throughout our discussions for this webinar series is the integration of customer resources to optimize grid flexibility. There's enormous opportunity for these resources. They are proliferating, particularly in some parts of the country and in pockets within those areas, but how we can best orchestrate these resources to provide grid flexibility and other needs without compromising the customer experience is a big challenge. And particularly as we'll be talking about here, understanding the bulk operations and electricity markets perspective on how to make this happen and what the implications are. So that's what we're talking about. I'm going to turn it over to Liang at this point to continue with the introduction. Liang, over to you. Thank you, Omar. Appreciate it. So we all believe that to achieve the vision of integrated digital grid, we need all the stakeholders to work together. So with the support from different sectors in June and July, we organize eight webinars and focus on different categories and a group of stakeholders. We have US utilities, European utilities, IT companies, universities, start-up companies, federal and the state government agencies, COPS research centers, and delivered eight webinars. And all of them are recorded. The recordings are available at both APRI Technology Innovation and the Stanford Bits and Wads website. I want to give a kudo and a special thanks to Aurelie Welsher and from APRI and Wahila Wilkie from Stanford. They spent quite a bit of time to pull all the recording together and upload to the websites in an organized way. And really thanks both of them for the outstanding work. And starting from August, and we organize the webinars focusing on different technology challenges. So the last week, we have this special webinar focusing on the grid resilience with customer DER integration. And starting from this week, today, we are going to discuss customer DER's integration in the wholesale market. And next week, we will have the topic discussion on the open standard data platform. And the last webinar in this month will be discussing the transactive energy, which is kind of hot topic based on the polling several weeks ago with all the audience. So without further ado, I'd like to introduce the speakers for today's webinar. We are very glad to have three independent system operator ventures from both East Coast and the West Coast for today's conversation. And we have Joe Powers and John Gooding from California independent system operators. And we have Tong Xinzhen from ISO New England. Three of them have been with ISO in the RTO area for many years. And I just want to have a quick introduction for each of them for their background. Joe Powers is the manager for infrastructure and regulatory policy at California ISO. Her current focus is on the policy and the modeling development advancing DERs in the wholesale market to further enable diverse technology participation. Right now, she is responsible for the California ISO energy storage distributed energy resources, so-called DSDR policy initiative. John Gooding is a senior manager for ISO infrastructure and regulatory policy. He manages a team responsible for formulating the ISO's market design and the policies related to resource adequacy, capacity procurement, demand response, and the distributed resources. Previously, he was responsible for the design of ISO's current suite of demand response program and products. John is a part of the California ISO original startup team back to 1997 and has been with ISO over more than 20 years. So our panelist from East Coast, Dr. Tong Xinzhen, is a technical director of ISO New England. He manages research and development projects for the regional wholesale electricity market. As the internal IND for the ISO, he provides technical consultation on the market and the system operations to the executive team of ISO New England and oversees the development of a marked clearing engine and the marked simulation software for the ISO. With that, I'd like to have Jill to help us kick off the conversation. Jill, I will hand this over to you. Well, hello, everybody. Again, thank you for that introduction, Liang. I wanted to start off by giving in the panel presentation from the ISO a little bit of information about the ISO. What's happening in California that is influencing DER development in the state and getting a lot of the ISO's attention? Then I was going to give some information on what the ISO has been doing to facilitate participation of DERs in the wholesale market for the provision of wholesale services. Then I'm going to hand it over to John to give you a glimpse of what the future might hold for DERs from a California ISO perspective based on our current experiences of market integration to date. So with that, a little bit of information about the ISO. We are one of the nine grid operators in North America. We are a non-profit public benefit corporation, although created by California statute. We are not a California agency, California state agency. We are governed by the Federal Energy Regulatory Commission. We are one of 38 balancing authorities in the Western interconnection, serving over 30 million people, including areas within the state of California, about 80%, as well as a small portion of Nevada. I did want to mention that while we serve customers, our interaction is not directly with them. Our interaction is with a smaller number of entities. We call market participants. We have about 221 market participants that we interact with. And they are the ones that have the interaction, direct interaction with the customers that we serve. Again, some of the information about our functions of the ISO, we use advanced technology to balance supply and demand every four seconds. Our operators are located in two control rooms, and we have pictures here of the one in Folsom, California. We do have a backup facility in Lincoln, California. And both of those control rooms are operated 24 hours a day, seven days a week. And we have recorded our peak demand way back in 2006 of 50,270 megawatts. We have not reached that record peak demand since then, although we did come close in 2017. The ISO operates markets for wholesale electricity and operating reserves. And those markets include day ahead markets, 15-minute markets, as well as five-minute real-time markets. Additionally, the ISO oversees an open and transparent transmission planning process that actively engages stakeholders' input on determining short and long-term infrastructure needs, as well as we have a robust interconnection process for new generators, streamlining their interconnection to the ISO's transmission grid. Having a little bit of difficulty advancing. So what is happening in California is there's an aggressive pursuit of a low-carbon future. And some of these goals have been met, even to date. The 33% by 2020, we have goals to get to 100% zero carbon by 2045, very aggressive goals that are having an impact as to the reliability of the grid. Additionally, deep greenhouse gas reduction goals are targeting an 80% below 1990 levels by 2050. Additionally, state incentives have been created to move the state to these greenhouse gas targets. These include a robust electric vehicle goal of having 1.5 million EVs on the road by 2025. 12,000-megawatt procurement of distributed generation by 2020, as well as 1.3 gigawatts of battery storage on the system by 2024. While these goals have been challenging for the ISO to maintain grid reliability, with less reliance on traditional large-scale fossil fuel generation, it has created opportunities as the industry shifts to the lion summer renewables for a high DER energy service industry. Doing the wrong. There we go. OK. So in 2018, the Federal Energy Regulatory Commission voted to renew barriers to the participation of electric storage resources in competitive electric markets, really with the goal of improving competition and enhancing system efficiencies while increasing resiliency. So this was established under the FURC Order 841, in which it established a storage participation model that would recognize, well, required the ISOs to establish a storage participation model to recognize physical and operational characteristics of electric storage resources and accommodate their participation in the wholesale market. Additionally, there was, within the notice of defining DER aggregators as a type of market participant. However, this was deferred within the order. And then, additionally, there's other state activities seeking to remove barriers to market participation by storage and microgrids. And this is found under State Senate Bill 1339, which has a goal of facilitating the commercialization of microgrids through more standardized interconnection processes, development of separate rates and tariffs, and just overall new standards for microgrids. And the CPUC has initiated a rulemaking for the State Senate Bill 1339 on microgrids. Again, additionally, attempting to remove barriers for wholesale market participation for these type of resources. I apologize, I'm just having the most difficult time advancing the slides. And I cannot find the little button to advance. If you can hear me, Jill, I have control of how I'm advancing them for you. Oh, OK. You're advancing them, no wonder. OK, so let's move on to some of the participation models for DERs to participate in the market. And as mentioned, there's been a lot going on in the state as well as at the federal level for many years. And so the ISO has been working over the years to develop these participation models for demand response, energy storage, as well as distributed energy resources. So there are models within the ISO that enable dispatchable load curtailment to participate in the wholesale market. And this is called our proxy demand resource participation model. And this allows for the aggregation of multiple end-use customers to provide services as a single demand response resource and with a value capacity value that is greater than 100 kilowatts. These type of resources have access to both our energy, those day ahead and real-time markets, as well as our ancillary services markets. They can provide spinning and non-spinning reserve. And as I will get into a little bit more detail about a load shift product that we have developed and is currently being implemented under the PDR participation model. Additionally, we've developed what we term as a non-generator resource participation model that was designed specifically for energy storage devices. And it does allow for distributed energy resources that are of energy storage resources to participate in the market. And this participation model allows for the variance between consumption of energy as well as production of energy. The very sophisticated model has a lot of different parameters that are utilized in order to optimize these resources within the market. And one of those is the state of charge optimization, as well as an understanding of these type of resources energy limits. And finally, we did delve into a participation model and really a framework for distributed energy resources in aggregate to participate in the market. We did kind of develop this framework similar to what we developed for demand response, but specific to different types of distributed energy resources and allowing them to aggregate these DERs and DERs that we're in front of or behind the retail meter. It did have some limitations in terms of the provision of this type of resource with requirements for a minimum of 500 KWs as well as a maximum aggregation limit of 20 megawatts. Now, since order 841 and the compliance to order 841, we have had to lower the minimum size requirement for energy storage participation to 100 kilowatts. But because this is an aggregation participation model, we've maintained the 500 KW requirement, minimum size requirement for this type of participation. Additionally, as mentioned, DERs could participate in the markets under a non-generating resource model. And this type, the DER provider participation model, was really developed for aggregation of very small resources. So it is limited to resources in aggregation that have sub-resources with a size less than 1 megawatt. So really, we now have participation models for generation that allows for the ramping between 0 megawatts to 20 megawatts as identified in this little graphic on the right, as well as we have participation loads that really look at the ramping of resources within the load area of the scale, as well as the non-generating resource that has the ability to look at both the consumption and the production of energy with parameters, specifically for both those types of services. OK, John, we'll go to the next one. So the most recent participation model the ISO has been developing is a load shift resource for behind-the-meter battery storage. This allows a behind-the-meter battery to not only discharge or curtail load, but to charge as a load-consuming device during negative price intervals. This participation model is developed under our demand response participation model, our PDR model. And this is how these type of resources that are definitely in the distribution system and are located behind the retail meters could gain access to the ISO market and participate and provide these type of services. And with that, I will turn it over to John to continue on with some of our future outlook. All right. Well, thank you, Jill. Appreciate that. And good morning, everyone. Again, my name is John Gooden. Jill and I have worked for many years together working on all things demand response and distributed resource related. Really, what I want to do is carry on from where Jill and her presentation this morning, which is kind of looking back in the past into the present and all of the steps and models that we've implemented over the years to enable participation from DR and DER resources and to lower barriers to their participation. What I'd like to do is just take the next few minutes and talk about the future. And as we move, and as many of the parts of the US and North America and the world really move to a clean, green, decarbonized grid, how do we ensure that those grids of the future, that that energy future is resilient? In other words, it can take and sustain stress conditions. It can take a hit of loss of a generator or transmission line and stay up and running. It's sustainable. It has longevity. It is reliable. And then it's efficient, both from an energy production sense and also from capital investment. So we have an efficient system, affordable system, all of those things. And so what I want to do is talk about two things that are somewhat related but are very important as we peer into the future. And number one is this concept of we have to make this duct, this sitting duct, fly. We'll talk about what that means here in just a sec. But essentially, we have to figure out how we can make the load profiles, those net load profiles after you subtract out the contribution from the variable energy resources, like wind and solar, that are largely non-dispatchable, how we control the grid once you've taken out those resources and the load that they're serving. And also, I'd like to talk about as my second point about if we are going to try to enable this future, we have to think about a different grid architecture in the sense that if we're going to have a more decentralized and democratized energy system where there's more local control and local resiliency through the use of distributed resources, I posit that today's operation and how we manage the grid is not ideal and it's going to have to change. Again, if we're going to achieve these goals of resiliency, sustainability, and efficiency. So let's just take a walk down this path briefly and talk about number one about how we make the sitting duct fly. I think most of you are familiar with the idea of the duct curve and how we're trying to operate the systems in very challenging ways. In fact, if your system exhibits a duct curve characteristic like California's, I would say that that's an unhealthy grid. And it is very challenging to operate the grid today. We have extreme ramps in the evening. And really, let me back up a second. Really, the kind of the situation we're in today in California is really attributable to really the success we've had, an incredible amount of participation from solar and wind and distributing the resources behind the meter solar. I mean, it's just been incredible. The penetration levels that we're seeing. But the impact of that is that we're trying to operate a system that exhibits this characteristic of this duct curve. And that is a real challenge, because like I said, that is an unhealthy grid. We have got to do everything in our powers across the industry to try to essentially create a more favorable net load profile. And we have to try to make that profile much flatter. What I like to say is it has to be less deep, which means lower ramp, less deep, less of that belly of the duct, and a lower peak, the head of the duct. So less deep, less deep, lower peak. That is our goal. We have to do that. And to illustrate that point, I'll just forward here to the next slide. Like I said, we have to leverage all these capabilities. The point that I want to make in this busy slide is this is some real-world data, or based on real-world data, is if you notice this red line on this graph, that is a portrayal of this duct curve to where you have this morning ramp. And then you immediately have to turn your dispatch for resources around and absorb all of this solar energy, in particular. Many times, we have too much relative to the load we have to serve, and so we are curtailing a tremendous amount of this energy. In other words, it's going to waste, and that's not going to work into the future. And then in the evening, we have these extreme ramps that we have to serve up until the peak in the day, which is now not your typical 4 to 6 p.m. Now, this is much later. Now, the peak occurs like 7, 8 o'clock in the evening. So there's this late shift in your peak. And then you immediately turn your resources around. Your dispatch will flee around and turn it down. This is a very inefficient way to run a grid. We have to figure out a different way to do this and to create a much flatter, more favorable profile. The way you see that is this purple dashed line. That's the goal. What we need to do is we need to store this energy or consume this energy when there's excess and discharge that energy or curtail that energy when there's a deficiency of energy. And what I mean is that in this morning ramp, this red shaded area is when we would discharge stored energy or curtail load or not consume load, which would follow us along this purple line. And then, again, in the middle of the day, you'd be charging up your batteries or your vehicles and storing that energy and releasing that energy later in the evening during that ramp, lowering that ramp, lowering that peak, creating a much more sustainable, operable, lower cost, essentially, profile. And that's really our goal is to do that, is to create a favorable net load curve. Now, that's a challenge. The thing we have to do is what's on this page here. We have to take actions across the industry, and I can't emphasize that more. There's been a tremendous amount of focus on the ISOs and RTOs and everything that they can do to help manage this net load curve. But the solution is bigger, broader than that. The solution requires actions on the retail side, not just the wholesale. It requires legislative and regulatory actions as well. And this is just a flavor of some of the things. But again, the message and the point for the future to have a sustainable energy, clean energy future is shifting and shaping load. A point I want to emphasize is it's not about reducing peak demand, which has been the goal of demand response and DERs for many years, many, many years. That's traditionally how they've been used. How do we serve those few hours in August when assistance peaked in that stress? How do we, should we have enough capacity to serve those hours? That's not the future. We have plenty of capacity on the system. What we need is to shift and shape all of those resources so that we can shift and shape that load in more favorable ways to be a flatter net load profile. And we can do that through storage, electrification, transportation, and regionalization, to where we can pick up the diversity benefits of a broader, more diverse grid, regional coordination. And the final point I want to make, and this is so important, is we need, in this lower left side of this column, is we need time variant and dynamic rate in a big way. Again, we need the retail side to step up here and ensure that we can expose consumers to time variant and dynamic pricing so that we all, individually as consumers, each one of us have the opportunity to help the grid and to change our consumption patterns in ways where we can save money and have the ability to do that through price responsive use and expose to rates that allow us to do that. Right now, the most extensive sort of time variant rates we have is time of use. That's the least time variant type of rate with the plethora of batteries starting to be installed, electric vehicles and people's driveways, solar rooftops. We need to have rates that allow consumers to take advantage of more time variant and dynamic rates with the technologies that they have in their possession and the ability to leverage those technologies for the good of the grid. So that's the point I want to make there. That was the number one point. In the future, we're going to have to figure out how to flatten out load curve and shift and shape our load and it's going to take the whole industry, wholesale retail, legislative regulation to make that happen. So we have to focus on that. Second point I want to make is getting to this point of the grid architecture. Again, if we're going to have a more democratized, decentralized local control, I pause it like I said in the beginning of my opening remarks that the current sort of top down system is not going to work. What I have portrayed here is this idea of essentially the soil, which is the bottom of this tree is sort of the transmission system, this organized network of transmission lines in a system that is then feeding these distribution networks that tend to be radial, tendrolled, much more, obviously less network. And what we're doing is we're adding many organisms to this tree, which reflect the distributed resources in that system. And again, the future, as many of you're seeing it, is that those DERs in the distribution system are going to start feeding the transmission system. It's just not one way anymore. We all heard this, we all understand it. It's actually happening in California. We actually have some circuits that are feeding in the opposite direction. And what that's begging is, what is that model that's going to make this system that is shown here in simplistic terms work better so that we have end-to-end feasibility from the very endpoint on the distribution system to the very top, the system at the transmission level. How do we make sure that that's feasible? And again, a top-down approach is kind of the approach that we're sort of on now to where ultimately there's this grand operator and grand centralized optimization of a system all the way down to the very last 10 rolls of the distribution system. Again, I posit that is infeasible and unworkable and that is not the future. The future is bottom-up. And I'll show that here next in my last two slides. This idea of grid architecture and this concept of a layered grid interoperability model is something that we've worked on in the past when Lorenzo Christoff is with the ISO, a Jeff Taft of Pacific Northwest National Labs and Paul D. Martini. This concept of almost like these Russian dolls, let me explain the bottom-up approach and why it's a better approach. And I think the architecture that we have to move towards is that essentially you're transacting at each of the boundaries or what I call here these red points, the points of interchange between each layer in the energy supply chain, each layer in our grid. And what's happening is that at each point of interchange, excuse me, is where you're transacting your overages, underages, in other words, your sales and your purchases are netted at this point. The beauty of this model is that you can manage volatility at each of the tiers at each level and you can incentivize folks in each tier to manage their own volatility. Another advantage is that it doesn't require deep situational awareness and a control of like a grand controller, grand optimizer. No, each layer is doing its own control and optimization. Which reduces complexity, makes this model scalable and allows for greater resiliency and security. A point that I'm gonna make is my last point and last slide is that also prevents tier bypass and I can't emphasize how important that is. So again, the point of this nested hierarchical grid architecture is that you're focused on what is the net interchange between each layer. I don't have to worry about what's happening in that layer. I only have to worry about what's happening at that point of interchange. This happens every day in the ISO and RTO markets with our neighboring balancing area authorities. We do imports and exports every day, every hour. Do I care about what's happening up in BPA or in the Southwest in their system? No, I don't have to focus on the details in their system. I only have to focus on what's happening at our shared boundary and what's coming in or out. And it makes it very simple and you apply that same concept to the entire energy supply chain from the building, micro grid, distribution, transmission, neighboring BAAs. Finally, my last slide and a very important point about this architecture is that it avoids tier bypass in the overall energy supply chain. I think everybody that's in the DER space right now is wrestling with very intractable problems of primacy, this idea of incrementality, what is the capacity value, value stacking, double counting, you hear all of these terms multi-use applications is another one. The challenge is, and again, it is intractable, is that under the grand optimization scenario, there is no answers really to these issues of primacy and incrementality. If you have a meter or a battery that's sitting behind the meter, it has a limited amount of fuel on it. So limited megawatt hours, that's represented on the left in this rectangle. If that's the amount of fuel you have, every supplier wants to be able to do demand management for their customer and they want to actually sell services and asset deferral to the distribution system. And they also wanna sell energy services and ancillary services to the ISO and perhaps even defer transmission as a storage, as a transmission asset. It is very difficult to balance and stack these values if you have a limited amount of capacity and energy. And who has first rights to that capacity and energy? Is it incremental? In other words, were you going to do that anyhow? So if you're gonna do time of use and shape the peak, why should I pay you at the next tier up to reduce load in those hours if you are gonna do it and already had the incentive to do it under a time of use rate, for example. And so this nested hierarchical architecture avoids to your bypass by essentially in each layer, you're solving your own needs, managing your own volatility, avoiding costs such as resource adequacy, for example, you're avoiding the need to upgrade the TND system because you're managing your loads, you're managing your volatility, you're reducing your peaks, you're managing your load at your level. And so you're avoiding a lot of these costs that we express today in explicit products. And so there has to be a way to capture that avoided cost value. And again, the whole idea is that you avoid this tier bypass, which is again an intractable problem that we're facing today because we're trying to solve these problems under today's architecture. So with that, I'm going to wrap it up. Hopefully that made sense. And turn it over now to our next guest. Perfect. Thank you, John, really appreciate it. Now let's move from the west coast to the east coast. Just a quick reminder for all the audience, you can type your questions through both chat and the QA features down the button. You can see two buttons here. You can type your question. Okay, Tong Xin, the floor is yours. All right, can you hear me? Yes. Okay. All right. Thank you, Liang, for the introduction. Hello, everyone. This is Tong Xin from ISO New England. And happy to be here. And nice to meet you all in the virtual environment. So as you already heard about the integration from California's perspective, Joe and John give you a pretty good introduction on the front policy, market design perspective, and also some of their thoughts on the grid architecture. I think those are the great presentations. My background is really on market operation and in an optimization. So I will give you some my thoughts on the de-integration in the ISO New England system and what are the future directions? So, okay, let me move on. Okay, so I put a couple of slides just for people who do not know anything about ISO New England. So this is trying to tell you what is ISO New England is about. So ISO New England, same as California ISO is a nonprofit organization is regulated by FERC and has three primary responsibilities managing the regional electricity markets, perform a day-to-day operation over the power grid and also perform system planning for the six states of New England. In terms of market, ISO New England manage primarily three markets, one is the energy market and service market and for a capacity market. Well, energy market is the place where people to buy and sell energy. And in the answer to service market, ISO procure answer services such as operating reserves and regulation services to satisfy your short-term reliability need for the power grid and the forward capacity market is really targeted at the long-term reliability which is normally called resource adequacy for the system. Once. So there are many resource-competitive supply electricity in the New England wholesale market. We have currently have 500 buyer size in the market. So in terms of the value of the wholesale electricity market it's relatively small compared to California. In 2019, we have about the total energy transaction, total money transaction value at $7.6 billion and $4.1 billion of which is in the account from the energy market and 3.4 billion is come from the capacity market. And the resource market is relatively small. It's only called, there's only have about $100 million. So the figure on the right shows the value of the electricity market in the past eight years. You can see a trend over there. You can see the energy market values going down and the capacity value. I mean, the value of the capacity market goes up. So here are some key facts about the isoning and the grid. We have a 7.2 million retail electricity customers counting, I mean, with the total population of 14.8 million people. And the season, I mean, the old time the summer peak demand is 28,180 megawatts recorded on October 2nd, 2006. And the old time winter peak demand is about 22,818 megawatts on July and January 15th, 2004. The ISO and union system contains about over 8,000 miles of high water transmission lines and it has 13 interconnection with neighboring control areas. Eight, you can see we have eight AC ties and one AC ties with New York ISO and two DC ties with Hydro Quebec and two AC ties with New Brunswick. The import, I mean, the interconnection with neighboring control area is very important. And in total, those interconnections serve about 19% of the regional energy need in 2019. We have a generation of demand resources they are used to meet the ISO and union energy need. They have a two, 350 dispatchable generators in the region, they're relatively large. With the total capacity of 31500 megawatts. So the figure on the right shows the source of the energy. So you can see in 2019, you can see that natural gas fire generator is produced 40% of the energy need for the region and nuclear produces 25% renewables and the hydros constitute produce about 16% relatively low in terms of generation output which are the coal and oil, they're only about 2%. But looking into the future, there are over 20,000 megawatt of proposed generation, the ISO interconnection queue, the majority of which is wind resources. And roughly 7,000 megawatt of generation have retired or will retire in the next few years. So this is either from supply perspective. We have those kinds of different type of resources. If you look at the demand side, we have 580 megawatt of active demand resources and 2,630 megawatt of energy efficiency obligations in the forward capacity market. So the distributed energy resources that are in fact is abundant in the ISO New England system. By 2019, we have 7,436 megawatt of energy 7 megawatt in total accounting for 19% of the operating capacity. And this figure below shows that the different types of DRs and you can see this, the energy efficiency solar with solar PV which including both non participating and participating resources are the majority of our distributed energy resources. There are 700,000 megawatt of gas and conventional generators which are DRs. And 450 megawatt, 58 megawatt of non solar renewables which including hydro, small hydro or wind resources. And also 214 megawatt for non VG demand resources. So those are the types of the DRs in our system. If you look at the participation of market, but the DR security can participate in our market. I'll say wholesale market through various programs. So there are listed them below here. There are demand response programs, sediment only generator programs and energy storage. So for the demand response resources, we have passive demand resources which include the unpicked demand resources and the seasonal unpicked demand resources. And when we talk about active, I mean passive demand resources, those are the resources that only participate in our capacity market and it's not actively presented in the energy market. We also have active demand resources which people can participate through the price responsive demand which called PRD program. So here on the figure on the right shows the DR market participation. And you can see that the purple piece shows that 60% of the DRs actually participated through the demand response program. And 22% of them participating through the ISOG program and 27% of participating actually did not participate in the market. Energy storage here, a list of a program here. However, there was very little participation in energy storage because we do not have lots of energy storage resources in current in our system. So in the next couple of slides, I will focus on some of the programs that have a direct impact on the energy market operations. So I will briefly introduce the PRD, ISOG and energy storage. So the first program is a PRD program. You can see that the load management, small BGs and so those type of program or load reduction can actually participate into the PRD program. So they can offer capacity, energy and service services to the market. They had to be able to participate in the market. They had to be certified some meeting requirement and also we use baseline calculation for the PRD program to compensate and monitor those resources. Those resources actually can participate through what we call the aggregation or a single resource that had a particular location. For a aggregation, they had to be registered at a DRR zone. We call the DRR stand for the demand response resources. So currently we have 20 DRR zones. And so multiple assets within the same DRR zone can be aggregated into one DRR resource. Assets across different DRR zone cannot be aggregated into a DRR resources. So for a DRR resource, they had to be capable of providing point one megawatt of demand reduction. And there's no single individual asset within the aggregation with a maximum interactive capability greater than five megawatt. This is a limitation is trying to eliminate, I will say, you know, eliminate their significant impact on the transmission system or eliminate the modeling accuracy issue over there. So a DRR resource, if they're large, you can be at a single location. So they had to be able to provide a point one megawatt of demand reduction and the maximum range of interoperability had to be greater than 10 kilowatts. And single, so DRR resources here in reality is not really a single asset. It can be a multiple asset, but they had to be aggregated under the same, I will say a single retail delivery point. So such that they can provide a price at a single pricing node. So move on to the next participation model, which is called the settlement-only generator. We call it ISOG. The ISOG in fact is a basic, is a settlement-only, is settlement construct. So those generated participating ISOG problem, the capacity results, they will receive a capacity revenue from our forward capacity market. However, they are not explicitly considered in the real-time operation, or you can see system operational or market clearing. They do not receive ISOG special instructions. They basically self-schedule themself by their owner. But however, they receive energy revenue and they were settled at a designated pricing location. In terms of eligibility, they had to be a resource connected below 115KV and had capacity less than five megawatt. Okay. The last one, the last participation model is energy storage. This is a program established under the first order A41. In terms of qualification, one or more storage facilities at the single point of interconnection can be aggregated and participate at the energy storage model. And however, they had to be able to inject and consume at least 0.1 megawatt. They can, similar to other program, they can provide capacity, energy, and service services. Under the current market design, they had to be registered at both a generator and a dispatchable demand. Okay. And we have two programs. All kinds of two operating mode. One is called the binary storage facility. And the other one is a continuous storage facility. So this, the participant can choose to which model they can participate depends on their choices of regulation services and also their operating characteristics. Binary storage model is mainly designed for a large storage resource that has a, I'll say discontinued opening range, such as a big pump storage unit. And continuous storage facility is actually for a more than likely target at a little bit small energy storage resource such as energy battery systems. Such that you can have very quick transition from charge to discharge. So as we discussed, those are the current, participation model for our DRs in our system. And we know that DRs can bring a lot of benefits as I'm sure you already heard about them already so they can provide the flexibilities, resiliency and few derisities. And however, they also provide a lot of challenge to the system. So in terms of the challenge, they can compose a distribution resource planning, transmission system planning challenges over there, grid operations and DR control operations, particularly market operation and also some challenges in the state and federal policies over there. So as we talked about the current implementation of our DR participation model, you can imagine that if you have a couple of DRs in the system and they're not gonna pose a lot of challenge to the system operation. However, when you have a lot of DRs and each one participating in the market, you will, that's gonna pose a lot of complexity for the system operation and also market operation. So in my mind, DRs need to be aggregated through a certain level of aggregation and participating in the wholesale market. So this figure actually is a concept of a figure. I talk, it's kind of a market architecture for a very short term, I would say a short term implementation with DR integration. So in this figure, you can see the eyes in the middle. So it's organized one market, which is the wholesale market. So both generators and load and the large DRs can participate in the market directly. And the individual DRs are connected with distribution system will not be allowed to participate in the ISO market directly. So they had to go be aggregated through the DR a, well, a new concept of the similar to our DR aggregator. So you can have a DR a aggregator who represented the DRs and offering a degree services to the ISO system. However, there must be some coordination between the ISO and the DRA and also the DSO here. I call DSO is the distribution system operator. That doesn't mean that the DSO will be a market operator and this construct. So the DSO is actually in an operator which is solely for reliability purpose for the distribution system or maybe it's that transmission system. So their responsibility, we're going to be the monitoring of their grade, not necessary transmission grade, their distribution grade. So they will monitor their grade and see and to report any limitation on the DRs to the DRA or maybe and also the ISO system. So the end of this construct DSO is purely, you know, is a reliability entity here. So in terms of the DR aggregation, here are some thoughts on the DR aggregation. I would consider DR aggregation is kind of a prosumer model. So in the way the DRs participate in the wholesale market through a DR aggregator, it will provide both all type of products which is in the wholesale market which is available for the wholesale market. Energy and services and the capacity product. The aggregator is solely responsible for submitting the bit to buy and offer to sell at the aggregation level. And they have to follow the ISO dispatch instruction and by disaggregating ISO dispatch signals for each DR. And it will also responsible for report the DR telemetry and communicate with ISOs on distribution limitation on the area output. And also we believe that no double compensation or double charges should be allowed under this construct. And the DSO and DSO as I discussed in the previous slide, DSO DSO should communicate with ISO on operational issues and the requirement on the DR. So the DR aggregation can be factored for the truck run. So here are some, I'm sorry. Yeah, it does. Okay, but there are some challenges with the aggregation model. Forced challenges is associated with the DR visibility. And you can see that ISO market is basically on the basis of the DR aggregation model. And you can see that ISO market is basically is at the transmission level. And each aggregator will be modeled at a virtual location through a distribution factors, which we show on the figure on the right. So then the ISO has no observability of the distribution system. It will actually, that will create some challenges. And for example, how do we, where do we map the DR? Because the DR is the active physical DRs. The DRs are connected to the distribution system. While in our system and most of the distribution system were not directly connected to the transmission system. In fact, they have to go through a sub transmission system, which is actually not modeled in the ISO market. And so that created a challenge to see where we should see the impact of DRs on a transmission grade. And also the challenge associated with that is also related to the configuration of sub transmission system and also the distribution system. So that really means even though you can determine the distribution factors, but there are dynamics associated with that. So that's depending on your operating state of your sub transmission or distribution system. So this created a mismatch between the market model and the physical model. And this is naturally lead to the next challenge which I call the special efficiency and transmission congestion management. And you can see a DRs presented in the wholesale market, the RA, I mean. So they add a controllable resources in the market. So ISOs will start using the RA to resolve transmission issues. For example, in this case, if there are transmission congestion happened in this red, you know, in the line showing red. So ISO will consider moving DR to resolve that issues based on their expectation and sped out in the distribution factors. However, this can create a couple of issues. One is how the DR is going to respond to this. So the DR can receive the signal and then decide which DRs should be responded to the ISO dispatch signal. Such response may not be, I would say such dispatch, DRAs dispatch may not be consistent with what ISO expectation. So they will, and in addition to that, the DRAs may create the, you know, DRAs in connected distribution system. Their actual response may not be also consistent with the DRAs instruction. So in the end, so the DRAs, the total actual DR response may not be able to relieve transmission congestion expected by the ISO. In addition to that, the DR connected in the distribution signal may cause the congestion, or maybe, I mean, what is the issues or the power quality issues in the distribution network. So as you can see that when such thing happens, you know, so the ISOs and the ISOs can actually coordinate on this by maybe by some of the manual process. So if there are, we can say that if there are, you know, if the hosting capacity in the distribution system is large and such coordination may not be happening a lot. I mean, once a couple of years, once a year, so there may not be an issue from this type of, to resolve those type of, you know, to perform this kind of coordination. However, when a large number of DRs are shown in the distribution system and create a lot of problems in the distribution system, then I'll say the current architecture may not work. This is a consistent with what John is talking about. In the future, we need something better, a great architecture. So in my primary thought will be that in the long run, we should have kind of a two-level of market structure here. So as shown in this figure, so on the upper level, we have the transmission system, you know, market, which is our existing transmission, existing wholesale market. And the DSO now becomes either a market participant or a market operator for a local energy market over here. So the DSOs will try to resolve, will monitor the distribution system and monitor and trying to dispatch DRAs and also the resource connected into their system, trying to resolve any of the issues raised in the distribution system through, I'll say, a DLMP concept. However, the DSO will be coordinating with the ISO or you can also say transact with ISO at the T and D boundary at the LMP. So in this type of coordination, ISO market will have very clear responsibility, all clear goal in their operations. So they will not face the complexity created by the DR integration. This concept looks simple. However, I think there are also challenges with this, especially from the state and very policy perspective. In addition to that, the reliability responsibility with ISO and I'll call the DSO market operator will have to be clearly specified. So in short, in my opinion, if you have not so many DRs in your system, a DR aggregation model should be considered in the future DR integration for wholesale electricity market and a proper coordination between the DRA, ISO and DSO should work in the short run. However, to fully resolve the DSO-TSO coordination issue, the local energy market should be tapped in the future. So with a large number of DR participation in the wholesale markets. So with that, I conclude my presentation and I'll be happy to take any questions. Thank you. Great. Thank you, Jill and John. We have a lot of questions and a limited time, so we'll try to get to this quickly. Just to start it off, and maybe just going to everyone, maybe starting with Jill, since we haven't heard from you in a while. I think a consistent theme has been this need for market evolution and the need for this role of a distribution system operator, a DSO, which we have largely in Europe, but not really formally here in the US. Do you see this as inevitably happening through the kind of the invisible hand or what kind of interventions are necessary in order to kind of establish this role formally in each of the areas. So just interested in some quick thoughts from each of you and maybe starting with Jill. Yeah, I think Thompson, he really laid out what the challenges were and it's not just one agency or that is going to be able to resolve this issue. The ISO has experienced these challenges in working with our utility partners, just even getting in a single DER aggregation into utilizing our participation model for the provision of wholesale services and it really gets down to what has been laid out here as the complexity of these aggregations and the coordination that is really needed between the transmission and distribution operations and without having these formal coordination efforts as well as the technology for the distribution companies to be able to have the visibility as well as the controllability of these DERs to ensure that they're not at an ISO dispatch or a wholesale dispatch if there's no reliability issues with them providing these services. Absent having all of that in place, there is real reluctance to even open up the ability for these type of resources to participate in the markets. So it's going to be a larger than just the ISO and working in partnership with the utilities. It's going to take a lot of regulatory effort at the state level to really put these kind of frameworks into place and really we really should be, as John has kind of laid out, at the long-term vision. We've tried to move forward incrementally into these participation models but really we have to get to that long-term vision to really have the direction and roadmap as to what we're going to do to get there. Great, thank you. John, I'm sure that any thoughts on that before we move on to the next question? I think Joe covered it, thanks. Yeah, I think Joe covered it pretty much on this. For me, I think this is a regulatory issue especially if your DER is participating in the wholesale market directly, that's under the first jurisdiction. But if you want to set up a local energy market, that actually falls in the hand of the state. And also the complexity involved in this great architecture, let's say your local energy market or the wholesale energy market, the reliability as I mentioned in my presentation is that the reliability responsibility had to be clearly stated, spelled out. Because for the ISO, if you want to do a transaction with the DISO market, so if we agree with one transaction, that means that the DISO is supposed to be a balancing authority now. So this is one of the questions whether the DISO should be able to do that and what are the mechanisms of maintaining such balancing authority status for the ESO, that's questionable. That's just another thought on this. Thank you. Great, thank you. So I want to... We have a lot of questions on the Q&A, but I really love the... want to spend another maybe three minutes to continue this conversation regarding the DISO. The question is regarding... if we want to form this DISO and be more specific to the recent experience for the FERC A41, then the DC circuits, for the NAIRUK and the FERC and utility provider, whatever the fighting we have and also the settlements we have. And what is the regulatory innovation? You think it should happen to form whatever the DISO as Tong Xin layout and also the Russian style that John pointed out physically that's very easy to achieve. You can have the boundary between different layers but financially from a multiple perspective the FERC A41 for the storage is a very typical case. The behind the meter and distribution level and your storage can participate in the wholesale market and the state likely will not have up-out choices but it does bypass different tasks. So what is the regulatory innovation need to happen to achieve this vision which is a separator of the boundaries or the form of the DISO to coordinate with ISO? I'll take a stab at that one. This is John Gooden. I think the regulatory innovation has to be the ability to capture avoided cost value down at the lower tiers. A big challenge we're having is that right now the only game in town to earn capacity payments is to participate in the wholesale ISORTO market, those organized markets. And so demand response to energy resources and as you know all the activities that Joe presented and Tong Jin that we've all done a lot of things in our markets responsive to FERC order 719, 745, 841 all of these regulatory compacts that enable DR and DER to participate in the wholesale market. And again the goal there is to capture generally is to capture capacity value. It's less about the energy rents that can be earned by participating actively in the market particularly like with demand response it really generally doesn't want to participate and earn energy rents because that's disruptive but it does want to capture capacity payments. And that model is a challenge and that we need resources that can participate and provide both capacity and energy and capture those values and do that without having to present themselves and integrate with all the complexity in the wholesale market. The regulatory hurdle or mechanism is again how can DR and DER capture avoided cost value to where they don't have to necessarily earn a capacity and express an explicit capacity payment out of a wholesale market but by their actions and by reshaping the load curve of that customer or in that distribution system under that DSO that they are reducing the need for peak capacity so they're earning an RA they're essentially avoiding an RA capacity payment and so how do these entities these DER entities how do they get value and capture value for avoiding the need for RA or avoiding the need for Ansler services by lowering requirements on the system through lower loads less volatility lower ramping requirements and ramping energy needs and I think that's one of the biggest challenges is how to express that value to these entities and these providers by allowing them to participate in their tier, within their tier and actively avoiding some of these costs and getting compensation and value for doing that rather than trying to squeeze everything, every tiny little device into the wholesale market and I think that's the challenge that we face is how to get that value as avoided cost value I'm going to jump in thank you I know we got a lot of other questions so we'll try to do rapid fire in the five minutes we have left so this is a question I guess open to all just a quick answer if we can what do you think would be the next R&D or technology innovation to bring DERs into practical grid operations and grid markets so next big R&D or technological innovation to bring DER truly into grid operations and markets quick thought on that rapid fire this is John I would say terms and retail markets would be a technology that could really help so that you could optimize the distribution systems again that's a big lift and I think just this is Jill visibility real time telemetry being able to understand exactly the contribution of the different DERs and the actual DER aggregation response I think thank you Lea, next question oh you are new Lea back to the previous point that John touched a little bit and the question is more toward the ISO New England regarding the capacity market and the question is about what is the purpose to shift away from capacity market toward capacity market to enable procuring the right service at the right time what's the perspective on that Dongxin maybe I am not quite understanding you are saying that there are proposals to shift the capacity market to a shorter time period are you saying toward the capacity market to enable procuring the right service at the right time basically it is a short time or different time frame of the capacity market I think most of the important thing here is if you look at our capacity market I think the time is very critical important we have and that's why we call the forward capacity market the capacity market is supposed to provide an investment signal for people to join to ensure the resource adequacy if you are talking about having a let's say even say we have a monthly or maybe daily capacity market I would say it would not give you a long term market signal such that people would not use that information to secure their I would say long or investment they will go to the investment bank to get the banks to get the long or money on the financial arrangement so that's why we are thinking that long term capacity market can provide a better signal rather than a short term but if you talk about different locations for example in our market we do have this concept of different locations we have the different capacity zones so that means that we have a price for different zones so different capacity have a different location have a different value so that will give a different investment signal for different locations but as you may mention that there might be some other attributes we did not consider for example some people will consider you know why should we consider any of the flexible different technology for example having a flexible capacity or maybe a secure capacity which has few inventories something like this that's the thing we have not thought about currently because we are trying to say we want to be a energy neutral and this market design I think but those are the good questions great a couple minutes left still have a bunch of questions to get to a couple questions related to the tiered framework that John you presented which I thought was a great way of looking at this so two questions one is should the nested hierarchical grid architecture that you presented there be applied so rigidly that allow no tiered bypass when services to be provided can be differentiated between wholesale and retail levels and allow for direct participation where appropriate can you take that in 30 seconds yeah I think you have to have a stricter tiered bypass but services can be coordinated by the operator at that point of interchange be it the micro grid or the DSO to the ISO those services can be transacted at those points but to have an individual device on its own bypass its operator and that tier say the DSO and without the DSO having an understanding go ahead and try to sell services into the ISO that's where you get into real problems to where it becomes almost impossible to manage these resources because you get into primacy, incrementality all those problems that we struggle with today thank you I think we are at the end Liang do you want to take us home and close this out thank you Joe Zhang and Tong Xin again really appreciate it is a fascinating conversation even today we had a very limited time for the Q&A apologize for all the audience we have not cleaned up all the Q&As but we are going to pass your question to the speakers and we encourage them to either write your answer to you or communicate it in different ways thank you again for participating in today's webinar and just a reminder next Wednesday 8 a.m. Pacific time or 11 a.m. Eastern time we are going to have the next webinar talk about open standard data platform thank you all for your participation thank you thank you thank you bye bye