 Thank you, everyone, and welcome to the Seminar. We are very happy that two speakers, Andy and Andrew, are here. I want to remind everyone that our next seminar is the first day at the same time. We have a speaker from Enric, talking about our system and tools. Let me quickly introduce our speakers. Andy is a principal planning and strategy planner in Portland, Seattle, United States, Distributed Resource Planning Team. He has over 10 years of experience in the energy industry focusing on distributed resources across both planning and evaluation. Andy has a graduate of Portland State University with a dual degree in the Department of Mental Studies. And your list of PTEs distributed in resource planning team is responsible for PTEs distribution system timing. She has over 30 years of professional energy experience in the energy industry, working in the utility, consulting in public sectors. She holds a Bachelor of Science degree in Environmental Science with a specialization in energy conservation and renewable energy from Iowa State University. So I thought that we'd start today's presentation off with a little bit of context study. There's lots of definitions of distributed energy resources. There's a national definition that the name group has, which I really love. It's not the definition that we use for GDRs in the state of Oregon. But the reason why I love Neighborhood's definition is because it speaks to the location of a resource. It speaks to the benefits that you get from those types of resources and then gives examples of those resources. So Neighborhood speaks to being close to a customer site, which is very important when you think about utility planning. We typically speak about assets being in front of the meter or behind the meter, being customer owned or utility owned. So being close to a customer site gives you a lot of availability to site that resource where you can. And that becomes really important when you think about things like solar, water scale, solar energy storage, or energy storage where you might not be able to site it on the customer site or you might be serving a needs that's at the distribution or transmission level. As you can see, DRs, I like to use that term as an umbrella term for clean energy resources. It includes both in Oregon's definition as well as Neighborhood's definition that it includes distributed generation resources, energy storage, demand response, energy efficiency, and electric vehicles. And what's not noted in here are some words that you might be familiar with, solar, and then also building electrification. So for contact setting, we are talking about those types of resources in this conversation. So what is distributed resource planning? This is a, really you can think of it as a type of planning that looks at people, buildings, transportation, and clean energy resources. And it's all centered around asking questions about people, who are the people we're serving? What are the types of buildings that we're looking at? What are their age, where they're located? And then what are the attributes of those resources? So, for example, transportation transportation is a good resource to look at because you have to think about how people drive that vehicle, how do they charge it? Can you use that as a demand response resource? Can you use it in terms of averages? Some of you might be familiar with the Ford F-150s and the people using those during averages in Texas last year, but it's really just trying to understand people and technology with us. That is kind of a broad overview. The reason why it's really important because distributed resource planning is not just an analytical exercise, it's an intersection between policy, statewide goals, regulation, but it also is part of how communities and stakeholders are people who participate in energy. Think about, you know, how do they clean their future? How do they have sustainability goals? How do they think about resiliency? So the team that Andy and I work on, we focus on answering these questions, and it's very, very broad. And I think it's very important that we actually participate in policy. In Oregon, we've really seen a change that has moved us to starting to think about DERs as a resource, and the landscape has really been focused on modernizing the grid, having an equitable implementation, and how we modernize that grid. And through those two things, that's created what we call a distribution system plan. The ways that have them, Oregon is unique. We really focus on equity as a core principle of our distribution system plan. It's very different than what we have in other states. And so I think the landscape of policy in Oregon and the progressiveness of Oregon's policy has enabled us to start thinking about how do we transform the grid into something that is equitable for all of those that participate in this. The additional distribution planning really focused on kind of this cycle where you started with low forecasting. It was very high level. It was just taking who are the customers who are serving the total loan, total peak demand across your entire service territory. It was doing system assessment, looking at the resources you had, what type of needs that you might have, you have the capacity and strength, you have a localized issue, you have to find what kind of needs specifically, is it a transformer, a feeder line, finding a suite of solutions, then putting it into construction, and then monitoring it. And you'll notice here that even though it is kind of a cycle, it never, the end process of monitoring and controlling those devices never really fit back into the planning process. That was a real gap. The other gap is we saw that our programs or DR programs like energy efficiency, and then the way that we connect to the grid for things like rooftop solar, we're not part of that planning process. They live outside of that distribution planning process. So our traditional delivery was really focused on this one way flow of power. And you really see that we're going to start with your main delivery of coal power plant all the way down to homes, but wasn't interactive. And that's really critical. And why this shift is needed when we start to think about distribution system planning. So here's what's different. As we start to think about distribution system planning, this transition from traditional planning to where we start to think about all components of the grid. We start to layer in DR programs, energy efficiency programs, thermostat programs, incentives for EVs. And we start to think about how they connect, not just to our distribution planning, but all the way to our trends, transmission planning and also our generation planning. So our integrated resource plan. We start to get more granular. So the DRP team looks at who are the customers in the home? What are the behaviors? What are the low profiles? We start to look at every single hour of today. We look at end uses. We look at different types of homes. So when we say residential, we will ask you, does it mean single family, multi family, condo or really attached garage, not attached garage? We're getting down to that granular level. And then we're starting to look at how the system is changing over time. Do we have the ability to connect new resources to the grid? That's called hosting capacity where there constraints. Then we, when we look at grids, we start to think about communities. We start to think about what are the things that our communities need. Do they have sustainability goals? Do they have initiatives to accelerate clean energy and for their plates and their buses? We start to look at locational analysis. We start to think about what's the value of siting with top solar versus putting in a new transformer. We think of resilience. That really opens the door to start using DRS as a resource. So rather than putting up holes and wires, we start to think about developing a new substation. We start to think about non-mar solutions, which are non-traditional investments, micro grids, but there's also this feedback loop to the community understanding what's important to them. Is this what they really want? Is this what they need? Is it equitable? And then we, when we're in project design, we continue that community input process. And we start to think about how can we put on system protections in order to use those devices. So as customers start to connect to the grid, how can we use those during long-term outages? How can we use those to be able to make sure that the grid is safe and stable for all of those that are on the grid? And then we start to monitor and control those devices and then feed that back into our planning. So the image that is on the screen to your left, this equitable energy delivery, this was our vision for how we started our distribution plan. And you'll notice in the previous slide, there was that one-way flow of power going from coal power to the home. We looked at how do you put the communities that we serve at the center of what we do and how do all your investment decisions and all of the different decision-making processes lead to the uniqueness of each community that they're serving. Quite different than what other utilities are doing. And the nation. Can I have a quick question? Oh, yeah. Oh, I should have said, please feel free to interrupt me and ask as many questions as you would. So PG in Oregon, is it a fully integrated, like vertically integrated, vertically integrated? So yes, like having all the way from generation to distribution. Yes. And how much of Oregon does it serve? About 50% of the retail load. And I apologize. I have that on my slides, so we'll go over that in a few. We should have put it up front, but it's about 50% of the energy for electric needs in Oregon. PG serves. And I actually just had this written down from a question I got yesterday. So about 50 cities in six counties across the state. And we have the major metropolitan area. So the fund is for your area. Yes. Yes. And we have about 650 and 680 meters. And that's about 250 plus substations. And so the planning of the distribution grid here is really for the first time in Oregon, taking a comprehensive look at how that all fits together. So this is a very new and very challenging. Exercise for the whole, you know, the regular regulator and stakeholder community as well as utilities and communities, but it's really been exciting to see it all come forward. So the distribution system plan is a regulatory requirement through the OPC through socket, UM 2005 and it's for all of the utility owned investors. And I'm best room utility story. And so that's Idaho power, specific power and then PG. And the next slide speaks to that regulation, really what the, the intent of the commission was to develop a distribution system plan and why it was important. And so the OPC really saw that a distribution system plan was going to be critical for them to realize their climate goals across the state. And so they had not just in addition to climate goals, but also equity goals. And they needed the utility to help them realize that vision. So the distribution system plan has really three main focuses that community at the center, but it is intended to foster transparency by giving access to the public on type of data that we have, how that data is used and what is the potential of the ERs. And then be able to use that data to make informed decision and gather feedback on how the grid should be modernized. The distribution system plan is a, well, I call it in your term plan. It sits by specific actions within the next two to four years and a longer term vision over the next 10 years. So for us, when we were given this requirement to build a distribution system plan, we started with, what is really the intent of the commission? What is their climate policy trying to get up? And then how can we make our DSP something that helps achieve the goals of the state and the customers that we serve? How often do you do one of these DSPs? Yeah, so the distribution system plan is new for this. Our first distribution system plan, it was split into two filings. We submitted the first filing in August of last year or October of last year and we'll submit the second part in August of this year. Then from there, we'll file every two years that distribution system plan will look at our VR forecast, what are the needs that we have on the system? What are the types of solutions we can implement? And then what's the suite of actions? And then that gets acknowledged as part of a regulatory process. And so you might hear this when we talk about energy, we talk about providing safe and reliable power at affordable costs. And our vision was to change that to safe, secure, reliable, resilient power that's at fair and reasonable costs. And I think the fair and reasonable is really important when you think about equity versus affordability. So you don't mind quick questions. What other regulatory policy at PUC is supporting the equity policy? Yeah, so in Oregon, we had a very, very big legislative session last year where a lot of our policies were focused on equity. We have, in the past, there was traditional interveners who got funding. They got money to be able to, or got compensated to be able to participate in intervening into utility processes. But those dollars were never available for community-based organizations. So last year, there was a bill that passed that allowed community-based organizations and environmental justice communities to be able to get compensation to provide their expertise in the decision-making process for all utility aspects. So that's one example. There's also a ton of regulation, which Andy probably could speak to around TE, that's focused on equity. Yeah, we had a house bill. Transportation legislation. We have an acronym, so I think there's a lot of those. I guess it was Transactive Energy. Yeah, you know that's it. Yeah, there's a transportation bill which focuses on calling out how much revenue a utility should collect, and then spend on putting charging infrastructure in different communities of interest. And stakeholders, as the commission went through a robust process to get stakeholder feedback to define those. And so that's defined as sort of, there's seven so-coastal communities, communities with low-income renters, BIPOC communities, frontier and rural. And so this is new. It's a new TE investment framework that's being rolled out. And I have a slide in the end we can get to if there's time, but house bill 2021, which is our 100% clean. Bill is also heavily informing now how utilities will plan for community impact of our, not only supply resources, but then how distributed resources factor into meeting our decarbonization targets. And so I think. So there's my earlier slide that was the policy landscape that's changing. Just pass some notes on that. But really it started with the governor's climate. So we started with legislation or executive orders, which focused on the modernizing the grid. And then also had equity components and has really transitioned into through a series of regulation and legislation policy. And to house bill 2021, which was enacted last year. And then we also have a, we also have a plan that has several components. It has a clean energy target, which you'll see on the screen is to get us to 100% clean by 2040, but also ensures that the investments that we make are equitable. So there's language throughout about the equitable implementation of the distribution system plan, equitable implementation of our integrated resource plan. But then focuses on DVRs as a community resource. So there's components around community, and there's a lot of other things that we can do. I hope that answers your question. And in short answer, like there's no shortage of commission directives to try to answer this question. It's the challenges. So that at the same level, lots of policy and legislation, and then at the commission level, they've actually hired a media director to focus on this. And there's a lot of policy or a lot of regulation that's coming out around this. So in the distribution system plan, we really had this focus to figure out who were the key partners in creating a distribution system plan. You know, the utility is one component, right? We have our own goal, we have our own strategies. The only things that we kind of care about and that we need in order to be a sustainable business. But we also have customers that we serve and those customers have things that they need and that are important to them. And then we have intervenors and stakeholders and partners who care about the customers that we serve and our advocates of different sectors, industrial or business sectors. And then we have our commission. So there's a lot of people who participate in a DSP. So we had to start with some very basic vision and goals. And our initial thought was just radical transparency. Let's just be honest with where we're at. What can we do now? What can we not do? What are we not good at? Where are we in our infancy and what are we really good at? Let's really lean into our community expertise. We are not equity experts. Let's just be honest. We are utility experts. We need to lean into our community based organization. We need enhanced engagement. This can't be just us speaking to our partners and our regulators and our customers. We need to have to a flow of information and be able to take their feedback and implement it into our process and it really has to be easy and understandable. I mean, nobody, they have a lot of people that come from a lot of different aspects of, you know, educational backgrounds, the expertise is different. You know, we just need to make sure that we're all kind of on the same page and understanding what are the goals and things we're trying to achieve. So we have this vision to be a 21st century community centered distribution system. And that vision is linked to our corporate goals, which are to decarbonize, electrify and perform for our customers. And that vision is tied to the goals of the state and our partners to advance environmental justice, to accelerate DRs and to modernize the grid. And with that we came up with five strategies. And these five strategies are focused on key areas that we think are necessary to achieve this 21st century community centered distribution system. It starts with empowering our communities, enabling their equitable participation in the clean energy future, modernizing the grid to make sure we can optimize the resources that are on the grid that are new and be able to continue to have a safe reliable system. Making sure that we have the ability to be resilient and withstand long term outages, recover from them quickly and then plug and play, which is access to the grid. How can you get, you know, if you want to be able to buy an EV, how can you get a charger and be able to connect that to the grid? And then finally there is an evolved regulatory framework. The model in which we operate is old and doesn't speak to this transition that we're going into. And we need to have a conversation about how regulation of policy is going to help us really be focused on this new transition. So evolving the utility business model is critical. So those are the key components of our BSP. And then I have an in the weeds slide that speaks to some of the things that we're doing here. And I'm not going to cover everything here, but if you see something that stands out, please feel free to ask me to go deeper. So our empowered communities, quite frankly, we are in our infancy and we're really taking the first step into this process. And the first thing we needed to do is build a framework on how do you do human centered planning? And what does that mean? And what type of data? Like what does it mean to incorporate DI into your work? And for us that means socio-economics and demographic data being a key component to our planning processes. And then how do we engage with our communities? We worked with three community-based organizations to develop best practices and develop some data analytics for us and put together a framework on how you would engage communities. So we leaned into their expertise and showcase their work in our BSP with their own words. We didn't rewrite any of their recommendations. We published it as they wrote it. And then we were very transparent with where we are on the DI maturity model. So where we're really strong is modernizing the grid. We're usually great at building things and keeping lights on for our customers. But there's a shift in how our goals need to be. So we need to really focus on people's position. We need to focus on assisting our environmental justice community. We need to think about resiliency. Security is big. It's safely using people's data, making sure that that's secured. And then reliability has to be there. That has to be at the core of what we're doing. So we started with the USDOE's distribution system planning framework. And then we looked at our current process. How are we spending our dollars today? And where are we making investments? We spend about $3 million into the distribution system, but only about $300 million on the distribution system. But only about $3 million is invested in grid modernization. So that's going to be a big shift for me. Look at our actions that we need to take. What is a part of the general grid case? Yes. So today, yes. Today is all part of a general grid case. Yeah. That's our capital expenditure. And so I'm more talking about the swing unit for the grid model. It's part of the general grid case. Yeah. And that's an average, I believe, over the last five years, right? Yeah. And so that's what Angela's indicating is that as we now pivot and modernize the distribution grid to handle these excess DQRs, that's going to shift our investment strategy. And I think, you know, typically our investment strategy has been capital investments, utility-owned investments, but as we start to think about modernizing the grid using customer resources, DERs, those typically are not part of a capital process. So they will require a change in how we make investments. And that's part of also the evolving utility business model, because those aren't. So as you're looking at the different problems and your goals from modernizing the grid and increasing resiliency in your evaluating potential solution, how do you evaluate the technology and then how do you work with tech companies to make sure that you're able to achieve your goals? Yeah. Yeah. That's a great question. We are in the process of trying to get to that ourselves. But we do, you know, I would say we have worked with quite honestly, we've worked with a lot of tech companies on a variety of things. We do work with a variety of engineering firms and I'll just give one example. Typically, we've worked with third parties to do our forecast for all of our ERs. We're trying to bring some of those things in-house to allow us to do more real-time data and analytics. So again, we have a similar tool that we're developing called adapter, which allows us to be in-house modeling and takes it's based python-based and then pulls in a bunch of other like Caltech and what are the other big... A lot of in-real open source models, but I think on the question, I think around how do we evaluate new technology. So just like a lot of other utilities across the space, PG and a number of years ago started developing more robust like applied R&D, we call it the grid edge team. So we have those folks out there who are engineers and working on next generation technologies so that like at the edge of the grid, so whether it's either new technology or just a new application of an existing one. So things like long duration flow batteries, for example, that's the reason why we just announced that we're doing one with a local manufacturer in the Portland area. And we do things with that group like micro grids and other things. The challenging part is always, it's an engineering problem. Lange numbers, talking about this earlier, there's a lot of engineering challenges, but then the business model and regulatory side to keep up with the pace of change needed to really meet these aggressive goals to decarbonize the whole system. Like if you zoom out and look at the US system, that's an insane challenge. So it's gonna need everybody cushioned in the same direction. And so it's really, on the technology side, we have a lot of companies always pitching I mean, utilities get that a lot. So we do recognize there's like a funneling problem of how do you not just entertain every single vendor that comes to talk to you, but then how do you actually, so I think there's some sense we could talk about the smart grid test that we've done, which is our sort of applied R&D sandbox. Yeah, there's combinations. I mean, there is, we have to do real time modeling, right? So when we think of technology to be of the ability to do that and not this leverage of black box technology from third party. So there are things that we need to bring in and we have more technical competency and capabilities around. We also have, how do you standardize different technologies? So ED charging is a good example. There's lots of different ways to charge your car, whether it's fast charging or level two, level one. And those things make it really hard when you're starting to think about how you connect to the grid. And I think that those are the areas where we can really invest in R&D and that's where we need to spend a lot of our focus and figuring out how we can do that. And it really differs between software and hardware companies. Like there's a lot of startups who, just because of the nasancy of those groups, it's hard to decipher what's a really good sales pitch versus how they actually perform interoperable systems between different providers that they're ever getting DVRs or just providing different services. So yeah, and what's like fully vetted, that you can connect to the grid and store safety and reliability. There's a lot there. The other components that are in our plan are resilience. This really came out, this wasn't part of our initial vision for the VST. We got our rulemaking in 2020, but in 2021 we had a series of extreme weather events. We had ice storms, we had heat domes, we had several days without power for our customers and that really brought to the forefront a need to make sure that we had a resilience system. And so we have key focus areas where we're looking at customer infrastructure, our own infrastructure, and then how do we make sure that we have the operational capabilities to be able to deal with long-term outages. Our plug-and-play initiative is, I would say still very focused on kind of the early stages or maturity there is, you know, in its infancy, we focused a lot about bringing transparency to how you can connect to the grids. We have GIS mapping that we did to show where there are substations that you can connect to without substantial interconnection costs and where we have areas where you cannot connect because they would cost substantial amount of money to be able to update the grid. So we have those two back me and then I would say for our filing that is in August, we hope to have some actual projects that we can propose that would help customers connect to the grid in any ways, whether it's solar inverter programs or EV programs, we wanna focus on time there. And then you can see in our bulk regulatory framework, there is quite a bit of policy that we need to coordinate with as we start to think about the distribution system and quite a bit of regulatory activities that we need to think about. But some key ones and the one I like to point out the most is in Oregon, we use an IEEE standard 1547 that is pretty outdated. It's not the most recent version of that standard. It is implemented into code and what it basically does is it doesn't allow us to utilize a customer solar system. It doesn't require a customer to put a smart inverter on their solar system and this presents a lot of challenges. So if a customer doesn't have inverter, it's not safe. We can't, if we have an outage event, we have to shut off their system. We have to protect the system for all customers. So it doesn't feed back onto the grid. We're really pushing the state to change that policy so that way requires customers to install a smart inverter so that way they can safely use their equipment during outage. But then also we have a time where we have not enough energy or capacity to be able to serve the system and we might have to shut down equipment that we might be able to actually call on that equipment and use it just like we would if we had a power plant. So that's a key example of some regulatory activity that we think could change and really help us modernize the distribution system. Excellent. Okay, so there's two more slides that I have and I wanted to dig a little bit deeper into two things. One is our power community and I think this is what makes our BSP journey which is leading with the DI lens. So there's a couple of components to that. The humans in our planning focuses on procedural justice making sure that our customers and our partners have seated the table and that they're not just at the table but that they have, they're able to be part of that decision making process. That's really important. Making sure that we have distributed justice is a key component of our planning. So that's making sure that we have equal benefits in costs that represent society. So today when we look at cost effectiveness, typically look at utility costs and benefits, we need to start integrating things like societal costs, greenhouse gas, air quality, and also customer benefits. What's the benefit of reducing anarchy and making sure that they're part of the cost effectiveness equation. And then restorative justice. We've had, there are quite a few things that in the past I think we didn't acknowledge that we did not look at all of our customers and serve them actively in their effect. It calls harm to some of our customers and we need to make sure that we restore that trust. For our community engagement, then I would say also for humans in our planning, I haven't mentioned this and it's not one of the bubbles but really should be is also data and analytics. So integrating things like US Census data, there's some tools out there through companies called Greenlink that bring me in socio-economics and demographic data, integrating that into how we do our planning. So for example, if we are going to be making an investment in an area, really understand what type of customers we serve. What are their backgrounds? Is English a second language? What's their income level? And making sure that we are equitably investing across our service territory. And then DEI, we've really focused on the core component is leaning into those community experts as I mentioned earlier. I was answering a question on the chat. Yeah, no. This also in the meat slide, but one thing I wanted to leave you with because this feeds into meat slides, is as we modernize the grid, there's a framework which we need to consider in the framework. Now it's not just pieces of physical equipment, but actually looks at customers and planning and starts to bring in things like a virtual power plant and looks at foundational capabilities, but also layers that into some more advanced analytics. So today, this is a suite of projects where we're at with four capabilities. And so Andy is going to touch on some of these, but I'd like to highlight our virtual power plant that is going to be able to allow us to combine different VRs and be able to use those to just like we would use as a power plant, which is kind of cool. Our doctor tool, which is our in-house modeling, which allows us to real time be able to see what are the impacts of the DRs in our system and how do things like policy, incentives, cost, change adoption over time. And then we have our ADMS system, which will allow us to have a platform. What's our VP has us, you mentioned this earlier when we were talking has a name for our ADMS or a little tag phrase. Or the IOC and ADMS will I make the nerve center? Yeah, the nerve center. The future of the grid. Yeah, our integrated operations center is our main center, which allows us to operate all of our assets and customer-cited assets as well. What does ADMS stand for? It's an advanced distribution management system. So it provides more real time sensing and controllable to current and other kind of dynamics like in the distributed part of the grid. Back to that really point where Angela said, historical planning was all done with like maybe annual energy flows or like at best like one peak time measurement. So now we're in this situation where because we have more two-way power flow, we need a lot better visibility of just what's happening. And not just for safety, like if line workers are out there, distributed generation of backfeeding on the grid and they're working on the wires, that's obviously a health and safety risk, but more for control of balancing out the loads is kind of what I'll get into. Okay. And so I do have- And the ADMS is the main platform and then the DR management system, they are all modules on that. Yeah, okay, thank you. I have a couple more slides on that so we can go on. So thanks, Angela. So I'm Andy, I'm a principal planning analyst on Angela's team on the distributed resource planning team. So I think before I jump in, I mean, first of all, thank you, Angela, for being the one to go along versus making me always be the one rambling. But not that you were. I mean, my slides, I have a lot of slides. I'm trying to say- We've heard that a lot. And it's always- I will go fast through these but I'll skip some towards the end just to save time and we can kind of go along after a good time. But I wanted to say a few things I'll just highlight from what Angela said. It's really kind of critical for how it works is different or at least like what we see as a really unique position is this community focus and customer first like attitude towards a great modernization and development of these DVR programs and how they get into the field. So I think there's some local initiatives that really are to the forefront like Portland has a clean energy fund which is focused on a just and equitable transition. So even though we mentioned the utility being in their infancy and how we deal with issues and racial equity within a planning process our recognition is that our communities are not that way. Like they're out there on the front lines trying to strive for justice in terms of how climate change and other aspects of this whole thing go forward. And I think you'll get a sense for those slides like how much activity is happening. I think Angela set the stage for really what's the policy landscape? What's the planning like high level? Even though we got into the weeds there there's a lot on the customer side of PG is really pushing on because we just recognize our customers are demanding it. If they demand more clean energy they want to reliable and safe they want to they expect that of their utility. And so I think it's my experience I used to work that in sort of energy efficiency and coming to PDE it has been very interesting to see that they're taking it that seriously. So a quick thing I mentioned I'll have the slide on our service area. So we are a vertically integrated investor owned utility with about 900,000 retail customers and we serve about half of the population I guess but 75% of the commercial activity. And then you can see House Bill 2021 we've mentioned is Oregon's flagship 100% clean bill and we have milestones in 2030 for 8% targets of around 400% by 2040. And you can see our current power generation makes on the right-hand side there. So as we work down towards phasing out that base load fossil generation I mean that's going to happen really rapidly and there's a whole host of challenges and opportunities with that. And that's a little snapshot of our service area and sort of where the generation comes from. But we're about, well, 3,300 megawatts a generation so in California you all are used to speaking the language gigawatts but we actually our peak load grew by 10% over the last summer because it was about 4,000 megawatts and we're dual peaking. So historically there's been a historic summer and winter split but during the heat dome events 116 degrees over multiple days we reached 4,400 megawatts on like three successive days I think so we shattered our past peak loads like multiple times last summer. And so for all the reasons of health and safety of our customers and the reliability of the grid there's definitely a huge focus now on I mean we also have ice storms and so there's a joint resiliency and kind of climate aspect to all of this. But we're really trying to build a foundation to deliver this reliable affordable clean electricity like Angela mentioned. And some of this stuff I'll go through talks to the modernized grid aspect of this but I think our group being particularly suited between the grid engineers and sort of the traditional utility activities and our customers and how to plan for this huge change. I think that's the really unique lens that our group has. So I'm gonna leave this up for a minute you can kind of browse at it. This is sort of the all in one I guess way to envision the ADMS and the sort of smart grid. As I mean this is probably a couple months tail I mean this is an active evolution both because I think as you mentioned these elements are going through rate cases and this is obviously a plan that is subject to regulatory oversight and community and stakeholder buy-in. So but this is how we're trying to envision bringing more DDRs into a sort of a platform where they migrated the grid towards away from sort of a commodity sales framework towards a platform with multiple revenue opportunities. And in the middle there is sort of the grid management system where we're rolling out EMS and expanded ADMS capabilities. So those some of the grid mod things which I think I have in the backup slides but some really important ones I think are like flizz or like fault location and isolation service restoration and distribution automation activities generally that's kind of on the grid engineer side so if any electrical engineers in the room I mean we have a ton of stuff in that arena but the stuff outside of the cloud I guess is what our group mostly is interested in like how do buildings and battery storage at customer homes, how can those aggregate to provide value? Do you have a question? Well, yeah I was gonna have to pitch. No, go for it. So the ADMS system, what is the time scale that it's looking to make decisions? Is it at like the 15 minute AMI interval reading or are you trying to? So we have AMI meters at about 99.9% of our customers with either 15 or 60 minute reads right now. So the ADMS will actually provide more like I don't know if it's every four seconds or every so right now the balancing authority so PGE is our own balancing authority. We have to on the intertides down in California we have to maintain frequency and other load commitments every four seconds and so those resources shift in a big way. So if 200 megawatts of our wind might cut out in five, I mean that doesn't happen in four seconds but the frequency reads come in every four seconds the IOC, which I guess it's not here but Angela mentioned that is it? I mean it's at the end of the terms it's actually still high. I'm like reading the graphic when you all come. You don't know how to read the words that you were reading. So yeah the IOC will be sort of integrating the distribution of transmission operations into one coherent area but I don't know the exact time step of the ADMS I do know it's more on the second scale versus and sometimes instantaneous where especially the flissur where those, I mean it depends on the function but I would say that we're definitely going more toward the real-time control, not invisibility. We're still building it out and we also have it completed. Basically the AMI is a 50 minutes meter so the scanner to see on the bottom left that's every four seconds in the scanner network. But that's not something that PD would build out. Y'all would buy that from the third party. We didn't want to, so we invest capital to do that and then we have a rate case where that gets adjudicated but we yes, we're not building that ourselves so we are contracting with the software for us at the moment. Our own tool, so we're having the third party build it for us but we will own it and operate it, right? So the AMI will be ADMS once it's set to module it'll be rolled in, it will be then probably through the EMS. So the AMI data will be aggregated through probably the data lake and it's available through, you know we have a team of data scientists that you know work on developing new ways to aggregate the AMI data and make it visible for grid operators. You know that's being built right now and we have some internal tests that were sort of the ADMS is kind of a foundational investment though because you need the actual measurements to come back from the field before you actually win a whole bunch of advanced analytics. I mean, you can get a lot with 15 minute AMI data if you can get in terms of like past patterns and then forming your plan. And we need to update our AMI meters. They're about eight, 10 years old they'll be in the process of being in a student list. Yeah, like the whole conversation around this is how much data do you want to store in your system like and for help? So like we can't collect voltage data and frequency right now from the meter but it's not that great in terms of using it for power quality real time management. So that's a question that people are asking us. But I do have a lot of slides and I know this is like you all probably I wouldn't advance past this slide if you, because I know that this is course we can stay on it if you want or come back to it. Does that answer your question though? Yes. And I am not the ADMS expert. So that's also why I want to move past it. But some of the interesting things I'd say we'll get into more I'm mostly in charge here at DER forecasting. So you can see some of how we lay that out and communicating back to this central system to coordinate those resources but that's all obviously in flight as still markets and regulatory contexts keep changing. So I think there's a mix of like law and business students in the course is what I was told. So I definitely all of this is very live across the industry and the West Coast in particular as decisions and different players are entering the market and it's disrupting the status quo in a big way. So it's definitely no shortage of interesting work in this field. That's something that you quickly learn as you participate. On the program, so I'm going to talk mostly about the program side. How do we forecast for things like transportation and transportation, but this slide is here showing flexible loads. So if you think about balancing new demands on the grid using these customer resources is one way to accomplish that with lower cost. So this is kind of our conception we're trying to move quicker from you asked earlier about technology companies and I would say this is more on the end of the hardware but we do have a significant amount of these all of these programs I guess these are all programs that I can talk through a couple but they like single family watergate is right at the middle. So PG has a pretty large compared to other utilities like we're going really hard after residential aggregated loads and being able to ship those. And so that's a program thing to go enroll more people in programs and give them incentives to allow this control of their device. And then we aggregate that up and use it as a peaking resource. But then that comes with who's the vendor putting the switch out there? What kind of software do they have to track and aggregate the data and provide you that that device level data that the power operations of control room folks at PG can actually see and rely on. So this is all kind of part of a demonstration moving towards programs as they get more mature on the right hand side. You'll see something called energy partner which is our larger CNI commercial industrial like load shedding program. A lot of other utilities around the country they might have like, oh, like 600 megawatts and it's in their demand response portfolio and sometimes a little bit not all the time but sometimes that can be like a curtailment error where you're just paying people to turn off their load. All of these right here are active shifting of loads. And so it's not just giving them a price signal. I mean, that's great. We don't typically have a lot of heavy industry in the Northwest. We have a lot of like high tech data centers and high tech manufacturing companies that don't want to curtail load but they're open to shift. Actually, you know, it's really a challenge of how to get those customers enrolled in any of these programs just as they have such a sensitive product line. But for all these other ones, I think PG is doing a really great job of casting a wide net. So there was a lot of variability in this where a lot of like diversity in the mix. And this is kind of 2021 as a snapshot. We had 82 megawatts of enrolled demand response and then 54 for venture. And this is a big challenge, as I said, because we're dual peaking. So a lot of other places can just run like Utah, I know Pacific War and other places like with California like some are people that are just such a driver and you have also a lot more cooling to curtail or shift. We're getting more cooling in the Northwest so it hasn't historically been a big deal. I mean, it's been a big deal but now it's taking on more proportion. But it's harder for us to get winter time for demand response because people may not want their thermostat to be messed with in the winter time when it's cold. And we also just have a more, I guess a higher penetration of gas furnaces and things like that, which you would need more electric heating in the winter to control, to actually shift that load. Okay, I'm going to check the OEM requirements. All right, transportation. This was kind of one of the areas we wanted to hit on. So the utility role in Oregon, it's not around the country, but in Oregon we're seeing a lot of activity around how can the utility accelerate the transportation transformation. So I'm not going to go into these, it's just a lot of different activities. One thing I'll call out is, I think in the R&D side, we're exploring things like pole charging we have up there. And that's to make it more equitable for people who don't have single family residences. They kind of park on the street and then it's actually cheaper to put the charger directly on the utility pole. So we worked with City of Portland to get that, you have to like change the city code and the ordinances, all kinds of stuff. So we invested a lot of time to working with those partners and now we're trying to figure out so how can we deploy this at scale? And so I'm just going to jump ahead because I want to touch on some of our modeling work, which all of this is painted a picture of like how do we get from this political context or a policy context towards actually planning the system and trying to figure out for the ERs that are coming more and more. So this is a study that we published with our first phase of the DSP. So it encapsulates a lot of what we're trying to do on the DRP team. And this is a study that was authored by Kadeo and Brattle with support from some other contractors. And what we did also is not just study the resource potential, but also build a model that we can then use because it's such a quickly moving market that we need to be able to quickly execute on new scenarios as the market changes. This is quickly an overview of the model itself. So we started as Angela mentioned with really deep market segmentation of who our customers are and what kind of devices they have that could enroll in a program and what's their load profile. Like how does that change over the season and over the, you know, every hour of the year. And then we look at going from left to right, just we call it measures, but any kind of technology that might be a EV charger or a thermostat program that we might want to control to shift load to make it more amenable to the grid. And then we look at the building stock and actually like for DMV, that's an example we use DMV data. And that's simulated every eight years or 10 years. So it's going to buy a new vehicle. So in our model, we capture it all at the site level and then sort of say, okay, now someone's going to buy an electric vehicle at year eight and we simulated out 30 years. So we're tracking everything at the site level to come up with a basically a system wide potential for all of these customer-cited resources. And then we get all the way to the right, we add some economic screening to really say, is this the right investment for people to make? And then we add some locational factors because we're all trying to tie it back to the distribution grid. So we're aggregating all these site level findings up to the distribution system. I'm just going to quickly touch on this and then I'll try to skip some slides. So this is our adopted model that Angela mentioned. So we moved towards that radical transparency lens trying to say let's not have another consultant like Blackbox approach. We wanted to build something that our communities, our stakeholders are regulators to really understand and engage with. You know, it's a work in progress but it's still highly technical and that is part of the barrier. It's how to make it approachable but we're using a comprehensive open modeling framework. So if folks are familiar with the CalTrack methods in California that was developed for sort of weather normalizing end use load data for purposes of evaluating these kind of end use approaches to controlling load. And then we're using Python to run this from end to end and we're incorporating a lot of like NREL and other DOE open source tool kits, like every pro light for you charging infrastructure, re-opt for sizing micro grids and things like that. And I'm not gonna go through all the bullets on the side there but it's pretty cool. So here's all the DRs we're modeling and these are growing actually. This was our last study. I think we just added a bunch of emerging tech like end use or electrolyzers for industrial direct use application for hydrogen and things like that which we're still working through but you can kind of see the big ones here. I mean, solar and storage and electric vehicles are typically what grid planners care about the most. Like demand response is interesting for programs people and it's important as that resource grows but historically it's been rather small but storage or solar and electric vehicles are the big ones. I mean, you all in California are like years ahead for solar than we are but we do see the current coming. And so I'd say on the right-hand side it shifts more into our demand response flexible load portfolio. So you can see all the different smart water heating and HVAC that we're modeling as well as some pricing programs that are on the right with peak kind of rebates of time of use just paying customers to like here's a behavioral signal. You can see it, it's a peak time of day and you need to reduce your energy use. So you all in California I think have the flex market which is pretty new but we're doing this in the context of a utility vertically integrated trying to sort of operate and control these programs. I'm gonna skip over a couple of these. I mean, we do some sort of statistical models and other things but I wanna give time to show. Well, let me actually look at here for a minute. This is our transportation. Just to touch on this, so in the model we develop basically a list of variables in that long table and then we're using some structured approaches to study which have the best explanatory power and then we only keep in the ones that are relevant and interpretable. But on the right-hand side we kind of see how we're putting these into buckets recognizing that because we're doing everything out of site level we need to know like how is income and location and like you can see up there there's a number of vehicles of the existing customer has a big impact on whether or not they'll adopt household income and other things like that how far they drive. So these factor in then we sort of get towards a locational propensity to adopt and this is kind of our scorecard. So we do this for every DR that I mentioned on that chart we compute a sort of scorecard like this where base points then get added and subtracted based on each of these variables to really be able to the important point here is to since we're doing it for all 900,000 sites in our service area we're computing this it has to be a scalable sort of solution so the model necessarily has to be simplified it can't be like you could put a lot more data science into this but it wouldn't scale it fast or at least it would take a lot more to build effort. So that's I think really interesting and I know we're close to time actually we're over time I can pause there if I need to close let me know how you want to do it. There's some questions. Yeah, I can pause there. I'll project those questions so that we don't get to see. We're working on the OSI for the EMS well I don't know about the EMS, ADMS, OSI but that's not confidential, don't try to put it in. Can I share more? Oh yeah. And the rest of the slides, they were super cool, I'm just kidding. It was more of the, I was just going more to the modeling approach I think that's all as you can say as I said like that's the flavor of what we're trying to do on the planning side to sort of keep pace with the rapidly evolving regulatory side. I didn't have a big takeaway conclusion so I'd say not to say anything. And Andy has answered those questions. Yeah, and with VPS I feel it's mentioned on there I think we do definitely on the hydro side like for Kermit like getting our spot market like the mid-sea, mid-Columbia, the series of dams that we take controls. We definitely have a lot more than the relationship that I indicated, which was more about balancing authority as transmission obligation, but so there's a lot of relationship there which I won't go into because I'm not the expert. Yes, so the second one's about memoirs solutions or also memoirs alternatives. And the OPUC as part of the distribution system plan requires that we propose at least two non-nuclear solution projects and they're not required to be cost-effective and that will be filed in our August filing and there is probably gonna be, I should have mentioned this earlier, we're in initial rulemaking so the commission will use our two filings to finalize the rulemaking probably in 2023 and everything we submit will inform the outcome of our final rulemaking but I would suspect Andy that memoirs solutions will be a requirement of our final rulemaking but we'll propose at least two projects in this round and Andy's working on the modeling for that, do you wanna speak? Yeah, so when we do, if we focus on two substations for example, the model that I was showing, we'll be able to then isolate for that geography how many multifamily buildings there are and that specifically has a different congruence of electric risk gas like heating or if there's a lot of low income building stock that could benefit more from energy efficiency and or there's just like, we know how many water heaters there are that we could enroll in the depend response program and one thing we're doing which is we're using NREL's PVWATS module to identify solar potential as well as their DGEN model which is a bottom up forecasting model for solar and storage and so we will run this model for those two locational non-wire pilots and then work with our communities again to what Angela was saying to make it community centered and driven to say, okay, here's the resource potential and how do we actually go get it? And there's conversations about, how do we actually invest in those communities to do the work themselves like installation of weatherization measures or solar and things like that. So it's going to be a lot, it's going to be like a pretty crazy five months. The answer to the second part of that question just quickly, the way that we're integrating equity into our decision making process is we have a portfolio of capital projects that we'll review. We prioritize those based on their ability to the priority of how much risk there is continue to provide safe level of power. We grant those as part of that for organization process but we'll also be doing is integrating socioeconomic and demographic data to identify areas that are traditionally underserved or vulnerable populations and then be able to prioritize those projects as well as the projects that also have safety and reliability concerns. Last question. Are you modeling at two substations because it's too difficult to scale out past that or you're just your hyperlocal eye? It's just that was the requirement by the PUC was to do, because we have to do two proposals that are thoroughly laid out with respect to cost benefits and equity considerations. So the model we have we'll be able to generate and look at any substation but what we will do is we'll have ability to run like parametric routes, zoning in on those two with like very much granular maybe avoided costs. So the avoiding cost of deferring a substation depends on where it is. If it's $10 million over here versus $20 million over there that gives you the pot of money you can actually defer and then that can go into a local program or it could be a big battery it could be a bunch of small batteries it could be no batteries and just a bunch of weatherization at demand response or it's over. It really depends on the context of what actually great constraint you're trying to solve for. Like if it's a peak load at 5 p.m. I can give you all residential customers that gives you a box of what kind of programs or customer side you could do. If it's more like an industrial growth where it's all flat you need to reduce that load over a much longer period of time. So you maybe need different solutions. Yeah the EV, we have about 26,000 EVs on the road and we're gonna, or in PG service area I should say. So I think we don't know what percent load it is now but I think we're projecting it to get up to about 20% of sales by 2040-ish. I mean 100% I wish. That will be a ways off. We're sort of closely modeling after California's 2035 ice ban. So like we do see like in 2032, 2035 timeframe there's a big inflection point in our forecast. We in Oregon, like we just adopted actually a clean trucks rule that follows California's and so definitely for medium and heavy duty I mean that is still very much emerging. We have some slides which we can show some of our partnerships with like Diamond Lake Trucks North America. They have their headquarters in Portland. So we just launched like a five ship public charging station for like all trucks. And so, but those are all still in demonstration mode. Mostly I mean California, you all will probably get those on the roads a lot quicker. I mean, Oregon's catching up whoever's watching don't get me wrong. And we will, we certainly have a lot of, we have our transit provider who's got plans to electrify or at least you don't have zero emission buses by 2040 for like 700 plus of their fleet. So we're working closely with them. School buses, we have a pilot program. I'd say I'm sorry, I'm not like sticking to the question but one of the lines could transmit the additional power is something that right now we're focusing on the DER and transportation forecast. The process over the next probably six months till we file the part two of the distribution system plan will be that other end of the stick. Like do we have the additional capacity? How much investment will that take? We're looking at distribution system obviously. And so I think for transmission that's something that the IRP would contemplate because they look at the bulk power flows and things like that. But we do include the EV forecast and IRP. So I think for now we're looking good but that could especially as the heavier duty vehicles if they start adopting more like megawatt scale charging at scale. Like to just do, if that's like an important business case for them to actually convert their whole fleet is they need to have rapid megawatt scale charging but that's, I mean, those are all game changers. So like this is, that's why we built this tool to be very flexible. And well, because six months after you do it it's out of date because the market is just so rapidly evolving. So today the model that Andy is building at forecast style what we think is the trend what's the most realistic adoption in the near term which was built on assumptions from 2020 you will be updating the model this year to be able to predict like 100% low like the question that that was posed here how does policy influence those states? The stable working house policy aren't initiative to go to 100,000 vehicles by 2020. Like over a million vehicles by 2030 and I think that's 50% of vehicles on the road by 2030 is our legislative target 25% of new sales in our sales by 2030. And then obviously, I mean, politically, right? There's policy that is not similar to California like any kind of other brands on ice vehicles that would change things in the out years. So this is all definitely, sorry, that's the best we can do on that one. Business model reforms, do you wanna talk about that in the, in the DSP, how we take that out? Yeah, yeah. So today we've been open to, you know, we've told the commission that we need to have a conversation around the business model reform. We haven't actually come out and said that there is any one specific model that works well. We've provided context on to the commission on different types of models. So it could be performance incentive, it could be performance, like a rate-based incentive. So we're looking to probably propose something in our second part. So kind of like the question that was previous asked that Andy commented on will be predicting impacts of EVs in our part two. We'll also be probably making some recommendations on utility business model reform in our part two. Yeah, I've been in the terms of the stakeholder landscape like Oregon has been looking at business model reform for a long time by recognizing that the utility incentives need to be better aligned with in order to move in a certain direction. But that's a complex stakeholder landscape. So I would say that in agreement with natural, like we're making efforts to say here's how that you shouldn't use something that is more of a dynamic expense, which typically then utilities, IOUs cannot earn rate over turn on that. They only earn rate over turn on stealing the brown infrastructure investments or long lived like IT investments. So the question is how to then motivate a utility to aggressively pursue something that is against their business model. I mean, that's the conversation. That's playing out in different ways across the country. So I think that's where we see that going. But it's definitely to meet our goals we recognize you need to get again all chips pointing at the same direction. Yeah, I would say that our particular focus in terms of business model reform is really as we start to shift in how we invest in resources, how do we recover and earn on those to stay whole as a company? Right? We need to be able to stole their bills and our employees. And so how do you do that? And still transition into that. And I think that this is a good question for a Stanford student to answer. Which one? So I'll pose it back to you. Number six word. Number six is I'm finding it interesting that they knew with the West Coast Clean Trends. I have a slide on that. This was 40 slides down from where I got to. So sorry, lack of planning on my part. But the West Coast Clean Trends was kind of a high level. So basically with that electrifying high five all the way from Mexico to Canada. And there was a nine utility partnership. PG funded that as well as a member of California and Washington Utilities. It's really meant to say like for corridor traffic up and down what is the infrastructure need? What is the next research questions from that study which was led by HDR group is really how does intersection of local delivery routes and like shares use of a public charging infrastructure and how like that really come to impact? Like how, like we don't know yet how people will prefer depot charging like overnight charging versus public fast charging for trucks and delivery. So that's very much like the next cutting edge questions of that. So it's impacting our planning to the extent that I mean, we promoted the study and we funded it. But it's ultimate use was to get more alignment across parties on the West Coast. And I think for how it hits our distribution system plan like until someone goes and says we need a super fast charging public industry service area that's when we'll start saying, okay, here's where we have extra ability to host something like that. So I was not PGA when that story that study was done. I was actually leading it for Pacific Corps and basically the outcome of that study showed that for heavy duty vehicles, you're going to have more charging outside of a major metropolitan area and you'll have more medium duty vehicles like delivery trucks within a city. And then also looked at their charging behaviors and the radius in which that they would drive and be charged. So I think all of that is encompassed in Andy's model or will be at some point and really just understanding what are the driving behaviors and the load needed to meet that those types of vehicles. So just to give you some scale for heavy duty vehicles, you would need the equivalent of a 25 megawatt substation to meet that load for charging at any given station. I mean, it's substantial. And I think that that's a challenge when we think about heavy duty transit up and down the West Coast. I see more chance in here like how well do you keep just going? Maybe, because I don't have a woman to do, but you all have a lot to do. I'm not a woman. We should wrap up. So thank you guys for coming.