The following is a transcript of our Power Insights podcast, Episode 1 DER Data Collection For Modeling And Transmission Studies.
Dave Angell: I'm Dave Angell and I'm with the Northwest Powerpool and this is a podcast on the NERC DER data collection for modeling and transmission studies. And this is based on a guideline published by NERC in September of 2020. We have three panelists here today to have this ... starting this conversation, and they are Ryan Quint from NERC, Ian Beil from Portland General Electric and Kun Zhu from MISO. I'll have each of them introduce themselves just briefly and then we'll dive into the podcast. So we'll start with Ryan.
Ryan Quint: Hey everyone, Ryan Quint here. I'm a senior manager at North American Electric Reliability Corporation. I lead a team that focuses on bulk power security, bulk power system security and grid transformation. That involves things like emerging reliability issues and areas of focus, one of those being the increasing penetration of distributed energy resources. So I'm one of the coordinators for the SPIDER WG activity and happy to be here today.
Ian Beil: I am Ian Beil. I am a transmission planner with Portland General Electric, been there about three years. I'm also a member of the NERC SPIDER Working Group that Ryan leads, and I'm a subgroup lead for a separate standard that focuses more on software vendor recommendations related to distributed energy resources. So we've been compiling documents that will guide if you use PowerWorld or PSSC or PSLF, one of the tools we need to model these distributed energy resources in detail. My day job at Portland General, we've been working on the last year, so I'm getting a lot of these DERs into our transmission models and seeing some of the effects we think they're going to have on the system.
Kun Zhu: Hello. I'm Kun Zhu from MISO. At MISO, my title is senior manager of generator interconnection, so we both do interconnection and retirement studies here at MISO. I also serve at the NERC SPIDER Working Group as the chair of the working group.
Dave Angell: All right, great. Well, I'll start off the conversation with some questions. I think the first question that maybe we'd go into a little bit about, this SPIDER Working Group. So what is SPIDER? It is the System Planning Impacts from Distributed Energy Resources Working Group, and they're the ones that develop this guideline that I mentioned at the very beginning. And so what I'd like to do is to find out how did this group get started, and how does it fit into the NERC committee structure and what's pertinent?
Ryan Quint: That's a great question, Dave. I can give a little bit of background. I think going back, say, two years or so even, maybe even a little bit longer, they're starting to become a lot ... They started a lot of conversation particularly in our planning committee. And we actually had our essential reliability services taskforce which turned into a working group. And under that, we had the Distributed Energy Resource Taskforce, and they published a technical report that was really like a landscape overview that provided a very broad-reaching review, analysis, assessment of distributed energy resources where we should be focusing our attention and identifying that it's beginning to grow. Say, in the last two to three years, DERs have really taken off in a number of areas. It used to be this, 'California' issue and now, we're seeing that many other areas, North Carolina, ISO New England footprint and many others are starting to see DERs taking off pretty rapidly. About a year, year and a half ago, in the Planning Committee, we really said, "Hey. We need to get a technical body together that's a group of subject matter experts that can really dive in and stop admiring the problem and start addressing the problem." And I think we've done a really good job of that so far. So that's the genesis of the working group is that it was system planning impacts because it essentially reported to the NERC Planning Committee. Well, recently, we've heard reorganization of the NERC Technical Committee structure. We now have the Reliability and Security Technical Committee which combined our Planning Committee, Operating Committee and Critical Infrastructure Protection Committee or CIPC. So now, we have one RSTC group that is the subgroups under that are intended to cover everything. So we're beginning to expand our scope a little bit and think about the operations, considerations and maybe even security considerations down the road. We still really like this name SPIDER WG, so we'll have to come up with a new acronym if we change our name. But for the time being, we're just starting to begin to change our scope, but really mainly focused on still planning things at this point because there's a lot of focus, a lot of work that's needed in that area in particular.
Dave Angell: What has the SPIDER Work Group produced today?
Ryan Quint: This has actually been one of the busiest, most productive and largest NERC technical groups that we've had in the recent past, I'd say with, I'd say, 200 or 300 members. Not everyone is extremely active, but a lot of observers, a lot of participants, and a lot of people are very interested. So that helps garner a lot of support and engagement in a number of our activities. We really have four subgroups under the SPIDER WG. We have modeling, verification, studies and coordination, and each of those groups has a fairly extensive work plan that boils up to the overall SPIDER WG work plan. In the modeling realm, we've published some reliability guidelines on the use of the some of the dynamic models, particularly the DERA dynamic model used to represent aggregate amounts of DERs for even larger utility scale DERs, is what we refer to them. So really, we've developed some guidelines around the framework for modeling DERs and planning studies in the study space realm, the dynamics realm, etc. Also, the purpose of today's discussion is on this DER data collection guideline and how we can gather data or should be gathering data for the purposes of executing planning assessments at the bulk power system. And then we've been working on other things like a survey and things like that. In this verification group, they're still working on some relevant activities. They haven't published anything to date, but they have an interesting guideline in the works related to verification. Studies has put out an assessment on the TPL-1 standard considering do we need to rethink things like system peak load and what we consider to be a generator and the modeling of dynamics?
For example, do we need to consider the dynamic nature of DERs? I think we'll get into that a little bit later, have a discussion here, as well as a review and actually a standard authorization request for MOD-032 around updating that standard to cover the facilitation of aggregate amounts of DER data for the purposes of planning assessment.
It's really that first step in making sure that we can facilitate that data transfer and then this guideline I'm talking about today is really intended to get into the details around what those requirements, that each DP and PCR are already required to develop, could look like particularly around DERs.
The coordination group has developed a working document around our definition of DER, which I think is important because everyone has a slightly different definition of DER. Ours is any source of electric power connected to the distribution system, and this document really covers what do we mean by distribution system? What do we mean by a source of electric power and things like that?
In SPIDER WG world, we don't consider the load side components to be DERs. Those are loads and we can have load modifiers like demand, response, energy, efficiency, etc. The DERs are a subcomponent of that that really being the sources of electric power, so distributed generation like rooftop solar, utility scale solar, very small wind farms, for example, or even synchronous DERs like trash burners and things like that.
So we can never forget that there are already existing small DERs out there that are likely synchronous like maybe even run over hydro and things like that. There's a bunch of things in the works, but that really is an overview of what SPIDER WG has done today.
Dave Angell: And also what we can expect for the future, it seems, so plenty of activity. That's very exciting. All right. Why don't we go ahead and drive a little bit more toward these particular guidelines. First question, just with the SPIDER Work Group, now what was the development timeline for this guideline?
Ryan Quint: The guideline has really been a work in progress for about a year or so, maybe even a little bit longer. We initially dove right into the concept of MOD-032 potentially needing to be updated and we had some really good discussions in SPIDER WG work group meetings, conference calls, etc., to highlight that there's a need for this information.
Some utilities really rely on MOD-032 as the venue for facilitating that data transfer between the distribution provider and the transition planner, planning coordinator. Other entities use other mechanisms particularly ISOs, in particular, likely have market rules and things like that that they take this already.
But some entities were very adamant about saying, "We need this information," and we use MOD-032 as our justification for making sure we get the right data. And so along those lines, we knew that we would have to go deeper in developing really clear, engineering level recommendations around what does it mean to gather aggregate amounts of DER data for the purposes of planning studies? So we published this guideline in September of this year and it was really about a year in the making.
Dave Angell: Okay. Now, switching to really the impacts from DER, and so I think maybe we would get some input from Ian and Kun on this. From each of your perspectives, how are DERs impacting the bulk electric system? Why don't we start from the ISO level, so Kun first.
Kun Zhu: Definitely, I believe different regions in the United States see different growth and penetration of DER. So MISO is in the Midwest region and also the South, new South region. We're not necessarily seeing the fastest growth of DER, but we do have some pockets, some states is definitely is much ahead of other state while some traditional states haven't really seen a big growth of DER.
But then some states already seeing big impact coming to the new system due to the local state or local incentives that those pockets start seeing huge number of like solar garden and other ERs coming to their distribution interconnection queue and requesting for interconnection.
So the new challenge we see is that in the past, when you see those less than one megawatt things here and there, you don't really worry about their impact due to the transmission build. It's not going to cause backflow or anything that the transmission will necessarily see.
But now, because there's huge number of new requests coming in, this becomes a new challenge to both ISO and also the distribution providers because we are going to face new challenges. For example, in the past, if we see something from distribution that's going to be impacting transmission, we can study it.
But now, when you have hundreds of requests all coming in at the same time, we can't really study them the traditional way. We are going to have a 10-year backlog maybe. So how do we coordinate, how do we study them? Those are all new things that are under discussion and I believe later, we're going to talk about the new FERC Order, DER order as well.
But even without that, just due to the penetration of DERs that we see, we definitely see different dynamic and different request and different need to address reliability and the coordination between transmission and distribution. It's still under development, so a lot of things will come out in the next year, I believe, as far as how we have to coordinate between the transmission and distribution to study those impacts.
Dave Angell: So Ian, you're with the vertically integrated utility in the Pacific Northwest in Oregon. Are you seeing such impacts in your area?
Ian Beil: I think one of the really useful impacts of being a member of the SPIDER Working Group has been the chance to get to hear a lot about places. In Portland, obviously, it's quite cloudy and we don't quite have the same level of DER penetration yet as some areas. But we've seen presentations from, for instance, South Australia, Hawaii, Southern California, North Carolina where system operators have way higher levels of especially rooftop solar penetration.
And that's caused a number of issues in terms of wide scale tripping for high-voltage faults or big changes in generation patterns. And so we haven't seen a whole lot of impacts in the Pacific Northwest to date, but I think we are more prepared for them just having had these conversations with other utilities around the country.
Probably the biggest change I think we've seen so far is just from a loads-low perspective, the mid-day and like April, May time period, we typically did not see flows on the COI and the PCI going south to north very often, and that's becoming more and more commonplace and it's driving flows on our system in Portland over transmission lines that traditionally hadn't been stressed very much previously.
So that's caused us to really look at how we build our base cases or what we expect the flows to look like in certain scenarios and redevelop what our priorities are as transmission planners.
Ryan Quint: I think that's a really critical point. While one area may not be significantly 'impacted' yet, other areas may be causing impacts regardless. So the fact that California is seeing a large growth in solar PB and other renewables, it's causing completely different flow patterns across an interconnected power grid.
That is definitely impacting neighboring transmission planners' decision-making around how do I project out my future operating conditions in a one-year-out case, five-year-out case, 10-year-out case? The concept of ignoring these DERs and the fact that flows are in the reverse direction on key interties is really important.
We can't overlook that consideration of DER. Otherwise, we would be assuming under certain operating conditions, we would have maxed out intertie flows in opposite directions where in reality, we're just not seeing that anymore. We're having to rethink the types of operating conditions we study, the development of our base cases, etc.
So I'd just add that as a really interesting point that you have to think a little more holistically here around these impacts because they're having these ancillary impacts other than just am I seeing tripping or am I experiencing overloads or etc., in my area caused by my own DERs? It's often caused by other's DER.
Dave Angell: Great. Well, that hit on two of my areas of questioning, kind of the operations which Ian hit, penetration in California is actually changing in the Pacific Northwest to such flows that we've never seen before. And then Kun touched on the impacts of so many DERs being proposed that really impacts the planning studies, how you approach planning studies.
So I guess, really moving into this particular guideline, how does this guideline really meet its goal? And I'll just go ahead and state the goal. The goal is to ensure reliable operation of the bulk power system in the long-term planning horizon. So from a very high perspective, how does this guideline achieve this goal?
Ryan Quint: That's a great question, and I think we've touched on it a bit here. But I think many regions are starting to realize that, like Ian was saying, if I don't have a significant penetration now, I could have it in the future. And I need to make sure that I am prepared for that future, and that is what we've heard from international experience that prepare early because the costs and the implications are severe when you find yourself underprepared for a system with a whole lot of DERs.
One of the first things that ... The ability around studies is predicated on the availability of data. And so the step of gathering enough information and data from the distribution world to create a suitable base case is paramount for the concept of planning. We need to be able to create base cases that we feel confident enough to make fairly substantial engineering decisions about, I mean, decisions that are on the magnitude of hundreds of millions of dollars or billions of dollars.
We need to know that the types of operating conditions we're studying in the future are accurate and reasonable, and we can put our stamp of approval on them so we can make those corrective decisions to keep the grid reliable. Fundamentally, the concept is, I think, very apparent that as DERs start to impact the overall net load, they're starting to have dynamic impacts.
We're seeing a need to explicitly model the aggregate amounts of DER, again, not trying to ever model really a single DER unless maybe it's a large utility scale DER. But the aggregate impacts of these DERs is really important to capture. I think it's worthwhile highlighting, for those that aren't familiar, that in the UK disturbance, they got a lot of publicity, and DER was a big component of that.
It was 500 megawatts of DERs tripping on rate of change of frequency and vector shift, which is a phase angle shift caused by the fault of them. So a whole lot of DERs, 500 megawatts tripped offline. There were other things that happened in that event, the tripping of a wind farm, tripping of a synchronous machine.
All of those things compounded and caused successful operation of the under-frequency load shedding, which essentially saved the system. But obviously, it gets a lot of attention when large blocks are loaded or disconnected. Would that disturbance have happened if any one of those things had not happened? Likely not or less severely, I could say, I guess, with confidence.
But not having 500 megawatts of tripping likely would have been a near miss, it likely would have a really interesting engineering study, but it wouldn't have got publicity. So is that an impact? For sure. And we've seen in North America, in California, we've been analyzing grid disturbances. We've just published a report on the San Fernando solar PB drop even that had about 100 megawatts of DERs tripping offline.
In 2018, we had the Palmdale Roost and Angeles Forest disturbance, again, where a bunch of bulk power system connected solar was operating abnormally. But in that, as we reviewed the net load quantities, we saw about 100-plus megawatts of DERs tripping offline and reconnecting five, seven minutes later.
And so again, all of that is impacting the overall bulk power system performance and that emphasizes the need to capture these things in future, in studies of future operating conditions in the planning realm.
Kun Zhu: I want to give a perspective, well, from my first take on this guideline. When this guideline first was issued, this draft, when MISO received this and MISO subject matter experts were reviewing it, we all felt this was very helpful because as I mentioned, we started seeing the DERs are coming into the footprint, and we know that we need to do something.
But this is still relatively new to our engineers. We know we need to do something, but what and how are not very clear. And when we look at this guideline, we felt that it's very helpful to guide us regarding what data we should request from the distribution providers, and then how we might use that in our transmitting studies. So that's very helpful.
And Ryan mentioned a field disturbance report, reports from NERC, especially the recent one, the San Fernando 2020 disturbance report. I think that definitely, again, triggered even more discussion internally here at the RISO, not even planning, but also real-time operations, how the DER could impact reliability and what are the things that we may not have thought about before, and what things we need to start thinking.
So all those are very helpful to help us to manage the impact or the reliability to transmit this and as we see more and more DER penetration.
Dave Angell: But Ian, from the perspective of the vertically integrated company, how will this guideline help improve reliability?
Ian Beil: My understanding, and please correct me if I'm wrong, Ryan or Kun, is that this guideline partially came as maybe frustration or just not having clear lines when there's a situation, when there's a transmission provider ... or excuse me, a transmission planner and a distribution provider that are separate entities.
And so part of what the guide is trying to do is streamline the processes, how you hand off that data and what data needs to be collected in the first place, and make sure everyone's on the same page, that distribution providers want to keep their customers' data as private as they can.
But transmission planners have a bulk reliability need at this point for some of this information. To that end, as you said, Dave, we are a vertically integrated utility of PGE. But that doesn't mean we haven't had our own challenges trying to get all this data. So we're fortunate in that our transmission and distribution planning groups, until pandemic, we worked right next to each other in the office.
We're not a massive utility, so we have enough flexibility to coordinate between our groups. But one thing that we've found in the process of trying to get more information on DERs in our system is that it's really a several step process. And so we've actually stood up a new what we call our distributed resource planning group.
They not only track all the DER on our system, but they're also building models that are forecasting five, 10 years out based on the economics of certain areas and the chance that people are more or less likely to get electric vehicles or a power wall, say. Or based on that information, what do we expect the penetration of DERs to be at this feeder?
And then the distribution planners roll that information out to the distribution transformer level, and they're able to provide what we call our minimum load forecast. This is actually something we've just developed this year where they're looking ... As a utility, we used to only be concerned with what's the peak winter and summer load on this distribution transformer?
And now, we're realizing that another stress condition is actually when that transformer's at very low load partially because there's all these distributed energy resources generating quite a bit. So the net load is very low, but one of the concerns would be if a lot of that load were to trip off ... or, excuse me, some of that distributed generation were to trip off all of a sudden.
So we, as transmission planners, then get to roll this minimum load forecast off into some of our light spring cases and model what it looks like when we have very low load and very high DER generation on the system at the same time, and look at both load flow and dynamic effects of all that.
Dave Angell: You bring up some good points from new modeling issues that we've really got to be focused on for the future. Okay. Now, looking a little bit more into the specific guideline, the guideline really has a single takeaway that's pretty significant, and it's really that the transmission planners and planning coordinators should update their data reporting requirements under MOD requirement, one of MOD-032, and indicate that it should have specific requirements for aggregation of DER data.
It points to the fact that 100 MOD-031 ... 032-1, excuse me, other information requested by the planning coordinator or transmission planner necessary for modeling purposes. So really, this seems like pretty fair technical justification stated in the guideline. But is there any real regulatory authority behind this? How do we actually accomplish this?
And I think maybe why don't we start with Kun because looking at it from the perspective of the ISO to a distribution provider?
Kun Zhu: From MISO perspective, we have been working on this anyways even without this guideline. We have been asking DER data from our distribution providers. In the past, the data was simpler, and now, we are asking more detailed data. And due to the jurisdiction consideration, our ask, that we name it as a data request, which means it's a request. It's not a violation if they don't provide.
It's good practice that they provide. At this time here at ISO, we do have this consideration that we have to pay attention to. So this time, it's a request until the MOD-032 is revised and there's some compliance responsibility both to a distribution provider. And this time, we're sending this data request as a request.
Ryan Quint: The current MOD-032-1 had the load serving entity as the applicable entity for distribution-related information. So really, I'm going to say 'back in the day,' that was aggregate demand levels and some information that may be useful for developing, say, a dynamic load model. But then on the west, we're very well-aware of. Well, now, LSC became a, essentially, deregistered entity at NERC at the registration levels. It doesn't really exist anymore. That led FERC to a gap, and the DERTF back in the day, developed SAR and submitted that.
And SPIDER WG's recent MOD-032 SAR really just reemphasize we need to get that addressed, and along with that, we need to clarify that DER data needs to be an exclusive line item in that table in the back of MOD-032. There is that catch-all but some distribution entities have really pushed back on that catch-all to say, "Well, why was everything else explicitly stated and now, you're asking for this additional data? I'm not buying it."
So some entities have struggled with that, and they have technical justifications. That's why they were asking for, in that SAR, to have it explicitly called out to get aggregate information. That's why Kun is saying, "Well, it's a request right now, not a regulatory requirement."
Now, if the DP was the applicable entity, which is what both SARs have highlighted, then there is some regulatory requirement to that. Any distribution provider that is a registered entity under NERC will be subject to that standard if and when it goes into effect.
For example, because for the current standard and any revision, they would say, "The TPPC is required to come up with their own data reporting requirements and the procedures, and the applicable entities of that data need to provide that information." And so the DP would fall under that as being required to provide that type of information. Hopefully, that explains the process of how MOD-032 works.
Dave Angell: Let's say MOD-032 is updated and distribution providers or registered entities were in a position of creating sound relationships and establishing a request and some sort of incentive for the distribution providers to provide the information, are there any existing models or processes that have worked fairly well that have come to be known in the SPIDER Work Group?
Kun Zhu: During the discussion, either at the SPIDER Working Group or here at MISO, we are not aware of a industry-recognized template or model that we would refer to. Definitely, always, we consult the state who has been dealing with this more often or longer than we did like State of California. But as far as if there's a model and template that we recognize as a good example, I'm not aware of that.
Ryan Quint: We're actually, in SPIDER WG, working on a forecasting guideline under the verification group. Really, what that's focusing on is how do we verify what our future planning assessment forecast will look like. When the process plays out that in MOD-032, the DP becomes the applicable entity providing information, the DPs have come back and said ... I think at first, they said, "It's too hard for me to get the DER data. I don't have that information."
I think now, we're realizing that we need that information and there are some best practices out there. There's maybe not a model like Kun is saying, an exact model for everybody. But organizations like Pacific Gas & Electric and Southern California Edison and stuff, they know where the DERs are located.
They're required to report that. When you put a rooftop solar in your system, you got to report that to Pacific Gas & Electric. And so they were able to say, "I know where my DERs are. I have accounting for that." And they can then use that to know where existing DERs are. But the distribution entity isn't likely the right body to say, "Well, I know what my DERs will look like 10 years from now when I try to create a 10-year-out planning case."
So we've come to the realization that there's this component of the resource planner who has, in the past, likely provide generation data, end use demand data, and now maybe even DER data as a component of the net demand. I think Ian mentioned that. I'd like to hear a little bit more from Ian around the concept of creating groups or expertise within the organization to focus in on this piece to track and be able to provide that out into the future.
Ian Beil: The Oregon piece, CIC has been pushing Portland General Electric to establish a distributed resource planning group for a few years now. And we have stood it up this year, and the goal is to use conometric models, so again, essentially looking at population and just trends and what type of distributed energy resources they might be expected to be procuring, and in what quantity over the next, say, five, 10 years.
Because knowing how much load or how much DER is on the system we have today is certainly important. But having a good handle on what that looks like five, 10 years down the road is going to have a huge impact on overall all the way up to our transmission models and how we build our base cases.
And it will have a huge effect as well on our distribution planners and some of the investments they decide to make or not make depending on the situation. Another thing I did want to mention too is I know there's some consternation from some utilities in SPIDER when we were talking about this data collection guideline just in terms of how much granularity do we need on this data?
Is NERC going to come after us if we don't necessarily know every rooftop solar facility in our system? I think Ryan's mentioned this before, but just the goal is to have something similar to a load forecast. It's not incumbent on us as a transmission planner to know the exact megawatt that we expect on the system five, 10 years out.
But we do want to at least have a general idea of how we might have 300, 400, 500 megawatts in distributed solar here in the next five years. And having a handle on what that's going to look like from a transmission perspective is going to be really important.
Ryan Quint: ISO New England has a really neat graph, and it's been shown in a number of SPIDER WG presentations in the past where they showed the year over year forecast of DER levels. And they showed that they've under-reported that estimate by gigawatts. Going back from 2014, they projected it out 10 years. 2015, they projected it 10 years out over and over now up to 2020. And they're seeing that that 2014 projection in the first year, that the one year out wasn't off too bad, maybe 5%, nothing too bad. But when you go out five years, 10 years, those projections start to get really, really off which is to be expected, but it's something we need to be cognizant of.
And so it drives the point home that we need to be running sensitivity studies like Ian was saying. There's no expectation that 'NERC's going to come after you' or something for not having the exact amount of megawatts put in your base case. What NERC compliance is generally looking for is do you have sufficient enough technical basis for the decisions you've made in your planning assessments, and have you covered your bases in your planning assessments?
So questions like, "You projected out this much DER, did you run a sensitivity on that, say, plus or minus 10%, plus or minus 15%? And when you did that, did you see any significant problems that you need to be aware of?" If I remember correctly, in the 10-year-out cases or maybe in five-year-out, I could predict, I don't think your corrective action plan has to actually be implemented.
It's just something you have to be cognizant of, but don't quote me on that. But that's an important point, that we're seeing a really strong need for sensitivity studies and sensitivities around DER is a great place to start particularly for areas where they're seeing a big penetration.
As Ian was saying, they need to be in the 500, 600, 700-megawatt range or whatever five years out, 10 years out in Portland. But the gigawatt level amounts that are maybe going into California, as he mentioned, are likely to drastically change the intertie flows. And that's going to impact reliability considerations up in the Pacific Northwest and something we need to be aware of. So all those things need to really be taken into account when we start running our planning studies.
Dave Angell: That leads us into the next portion of questions here about size. Size matters. So is there a penetration level where modeling DER becomes important or essential?
Ryan Quint: I can start, and I'd like to hear from Kun and Ian on this from a actual ISO and utility perspective. But what we've talked about in SPIDER WG in particular is that there really is no blanket penetration level or specific size where we can say, "Below this level, you don't need to consider it. Or below this level, you don't need to model it."
Your entities may come up with guidelines or recommendations or even procedures around how to handle this. But the good example that I always give is maybe I'm a utility with a load of 10,000 megawatts or something. I may have one utility scale DER solar resource out on a weak 115 kV network in the middle of the desert.
And maybe, say, it's 15 megawatts or something like that. In terms of the total penetration level, it may be the only resource I have in my network. And so the penetration level is a fractional percentage. But that 115 megawatt utility scale DER solar farm may have a fairly substantial impact at that 115 kV network particularly maybe if it lacks a reactive device or something up here to be able to maintain voltages.
So you stick on a DER and all of a sudden, voltages are fluctuating on a daily basis, or when the cloud cover comes in, things like that. That drives the need in that local area to consider that DER. That DER may be considered pretty darn impactful to that local network.
And so transition planners that are running local studies are definitely going to have to account for that kind of thing. Now, when I develop my interconnection-wide model, I may have a little bit more leeway on that, the impactfulness of that on an overall basis. But it's hard to say any blanket percentage matters or any blanket size matters because it's really dependent on the system and the challenges that that system is facing.
Kun Zhu: This is Kun. I agree with everything that Ryan's said. And from a transmission planner's perspective ... Actually, it's a true statement. Size matters. And from the transmission planner's perspective, an engineer, they know where, at which specific location, how much would matter. But I want to come back to the original question. I know some people ask that question, and it's not asking that from study perspective. It's more asking from reporting perspective, from institution side. Their worry is that do I really need to report this if it's not much?
But I think there are two clarification we'd want to put out there. One is that what the transmission planners are looking for is really a estimate like Ian already covered that. We're not necessarily looking for specific individual installation. We're looking for the estimate end of the aggregation.
The second is that if you already know that your DER level is less than this much megawatt, which means that you already did a estimate or forecast, so you already have that information, so that shouldn't be a burden for you to provide that estimate or forecast to the transmission planners.
Ian Beil: Just to give some numbers at least in PG territory, we have, we estimate, around 200 megawatts of distributed energy resources out on the system. About a third of that is resources that are 10 kilowatts and under. If we weren't tracking all these little rooftop solar facilities, we would be shorting ourselves maybe 60 megawatts of DER in our territory. Obviously, that is expected to increase here. To the extent that utilities and distribution providers can pack these resources with as much granularity as possible, it will certainly affect the accuracy of the models that we have.
Dave Angell: We talked a bit about the MOD-032 standard. There's a couple other standards with regard to size and modeling requirements that affect generator operators. Is there any consideration for adjusting a minimum size requirement for reporting on those?
Ryan Quint: Yeah. That's a question, Dave, that comes up a lot. For example some of the other standards, MOD-026 and 027, we then jump to a whole different world because we're then talking about bulk power system connected facilities and we're not talking about distributed energy resources anymore. So we have to make sure we stay within our wheelhouse. But in this conversation, we're talking about DERs, which are fundamentally located on the distribution system. Now, when you go up to the bulk power system, there is a bit more clarity on jurisdiction and things like that.
Currently, there are size thresholds in the bulk electric system definition that apply and that certainly dictate which resources are within NERC's jurisdiction and then which standards then therefore apply to them. I can't speak to the changes in thresholds or anything like that on the size criteria.
From a NERC perspective, I think there has been discussions in our Inverter-Based Resource Performance Working Group, our IRPWG group which is the bulk system connected stuff for that discussion goes on, there's a lot of resources that are below that, say, 75-megawatt threshold for dispersed-power-producing resources like wind and solar facilities that don't have meet these requirements.
And in the IRPWG world, we have really stressed through some approved industry-wide reliability guidelines that we need to rely on the facility interconnection requirements, the FAC-1 and FAC-2 type requirements to ensure that utilities are getting the information, the performance, the data that they need by establishing clear, consistent and concise interconnection requirements to get, say, good types of models, verification of those models and even performance of the fleet for those resources that are not in our jurisdiction. And there's a growing number of those types of facilities that are BPS-connected, non-BES resources.
Dave Angell: The impression, reading the guideline, that I received was it's really about aggregate data. And then I see there's quite a bit of request for specific distribution, specific parameters on page four of the guideline. So really, why was this included and how does this fit into the picture of this guideline?
Ryan Quint: Really, the goal is for the transition planner and planning coordinator to do some critical thinking to come up with clear requirements, modeling requirements for their data collection process for the planning assessments, really the MOD-032 overall process, how that works.
The TPPC needs to come up with detailed requirements. That does not necessarily mean detailed requirements for every DER component. So we need aggregate amounts of DER information. And then depending on the network, and how the network is set up, and how the transmission planner models these types of resources which can differ from entity to entity, some additional information may be needed, things like the T2D interface transformer impedance because that's going to affect voltages.
And so when I'm doing a dynamic simulation and some of my DERs are going to get tripped, I need to have a reasonable impedance between the bulk power system and the distribution system. I can't just ignore that quantity because my voltage profile will be likely very different.
We've seen that concept happen fairly regularly even with bulk power system-connected facilities. Now, in the guideline on page four/five, it does talk about the study space modeling type of things that would be needed. And it explains a mapping document around the individual distribution provider is going to know a lot of information about location.
If they're gathering information on location of each DER, that information is likely available. But a planner doesn't want that information. They don't want to know where every roof ... the address of every rooftop solar system. What the planner needs to do is divvy that up to the appropriate T2D interface because that's typically what's modeled in the planning study.
As a planner, I need to know how many megawatts are on this T2D bank, how many megawatts are on this one. What's the type of DER? Maybe when was that DER installed? What was its interconnection date? Because then, I know is it a new inverter, is it a legacy inverter, and the applicable IEEE standards really drive how that device is going to perform.
That's what we've seen in the California disturbances is that it's very likely that the resources that are tripping are legacy inverters that were designed to trip when the grid hiccups. The newer inverters probably don't have those types of problems. Having the aggregate information allows us to model the aggregate P max value we would stick in a base case.
And then as we get distributed energy storage devices showing up, that may change the landscape here quite a bit because our DERP mean value may no longer be zero. It could potentially be negative as a whole bunch of energy storage devices are charging, so another complexity that is thrown in the mix here. Hopefully, that answers some of that question.
Dave Angell: Yes, it did. Thank you very much. All right. Moving ahead into the dynamics data, is there a particular entity that would be responsible for ensuring that the correct model is used between the RAEC, ABCD and who knows what we may have in the future? Because there's not a specific generator owner that is identified in this process.
Kun Zhu: As far as the dynamic modeling of the DERs, since we're not going to model those individual smaller DERs, we're going to model the aggregate effect of the DERs, then the transmission planners need to use the aggregate data they collected and model [inaudible 00:46:27] their planning model, transmission planning model.
But there are certain several guideline that can help them. One thing was a product the SPIDER Working Group issued that Ryan mentioned. That guideline was a DRA model parameterization guideline. That guideline will help the transmission planners to set the parameters if they're going to use the DERA model to model the dynamics.
Dave Angell: The key on that was that the transmission planner is the one that's responsible for making sure that they have the correct model. I'm going to move forward just real quick into the short circuit area. And maybe Ian can answer this question. With the distribution, step-down transformer impedance size and the size of these DER systems at the aggregated ... and consideration of typical source and cadences in the transmission network, how likely is the short circuit duty to change enough to require any sort of protection or break or changes in the transmission system.
Ian Beil: My understanding is actually that a fault duty from DER is generally expected to be a lot lower than a traditional synchronous generator. But with a synchronous generator, you might be looking at a fault current at like six or seven per unit versus DER's is way down at like 1.2, 1.4 per unit. Just given the power of electronics, they're able to respond a lot faster and prevent a lot of this bulk current from happening. I would say it's probably, and maybe Ryan and Kun can speak to this more, an area in the SPIDER Working Group that we're hoping for more participation from protection and controls engineers. But it's just we haven't quite had that input maybe into those areas as much as we'd like.
Ryan Quint: One thing that we do put in the guideline, and it's a little bit futuristic, if you will, but it's a very thought-provoking concept, I think initially, when we've started, we've said, "Short circuit duties aren't going to drastically change with the inclusion of DERs offsetting net load."
But I think the big thing is that as the DERs offset net load, they change the bulk power system generation mix. And so we're used to running short circuit studies where we just put all the generators on and look for over duty breakers and things like that.
I think we need to rethink that, and the protection engineers are coming to that realization around what about a future where the grid is operated entirely by DERs? At least maybe even they're just under one hour or half an hour. And maybe it's not the entire system. Maybe it's a large portion of the system.
Think about California, for example, where the net load is almost zero because it's almost entirely provided by DERs. Now, in the fundamental short circuit, we would say, "Well, we have no generators and we have no load, and we're not modeling the DERs, we're not modeling load. So we don't even have a model because we didn't turn anything on on the bulk system."
And so have we really started whether protection will even operate accordingly? So maybe it's not a breaker duty question, but maybe it's a relay coordination question around are our relays still set appropriately when the grid is so drastically different than our operating condition?
What we laid out in the guideline was a transition process around maybe today, it's not so impactful. But in the future, maybe we will need to rethink the way we run these types of studies in the protection world, the short circuit type studies because of this drastically changing resource mix.
Dave Angell: That is a great response and a good way to wrap up this session. This is just the start and we're talking about a transition, a very specific transition in the electric system as we move from the traditional, synchronous, routine base load units to a future of inverter-based, renewable, variable resources. Things are going to be different, and our job as engineers is to figure out solutions as these things come along.