Energy Storage Grand Challenge Use Case Workshop (Text Version)

Below is the text version of the May 13, 2020, Energy Storage Grand Challenge Use Case Workshop presentation. View a recording of this presentation.

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Good afternoon. Thank you for joining us. We are going to be starting at 3:00, in about four minutes. Thank you.

Good afternoon and welcome to the U.S. Department of Energy’s meeting and it is being recorded. Welcome to the Department of Energy’s Energy Storage Grand Challenge Use Cases Workshop. We are pleased to have all of you here with us today. I’m Meredith Braselman with ICF Next, and our team will be guiding you through the workshop today and the workshops throughout the month. But first a few housekeeping items. In the chat box we have two links. If you would like to use close captioning, please click on that link and if you would like to register for the upcoming regional workshops, we have also provided that link in the chat box. Please note that this WebEx call is being recorded and may be posted to the Department of Energy’s website or used internally. If you do not wish to have your voice recorded, please do not speak during the call and if you do not wish to have your image recorded, please turn off your camera or participate by phone. If you speak during the call or use the video connection, you are presumed consent to recording and use of your voice or image. If you have technical issues or questions, you may type them in the chat box and select to send to the host. We will be muting your lines in order to minimize background noise.

Now, about today’s workshop. Pursuant to the Department of Energy Research and Innovation Act of 2018, the Department of Energy established the Research Technology Investment Committee, or RTIC, to identify potential crosscutting opportunities in data-applied science and technology. The Energy Storage Grand Challenge is managed by this committee. On May 1, we hosted a workshop to provide an overview of the Grand Challenge. A recording of that workshop will be available on the Energy Storage Grand Challenge website shortly.

Today we are going to go into more detail about the six energy storage use cases that have been developed by the Department of Energy and the National Labs, and you will be able to ask us questions through Q&A. To help us get to as many questions as possible today, as our panelists are presenting, we welcome you to submit your questions in the chat box and send them to the host. Because we are going to hold all of the questions until everyone has spoken, please reference the speaker or the topic when you submit your questions.

So, to get us started today, please welcome Eric Hsieh from the Office of Electricity. Eric?

Thank you, Meredith. And thank you to all of our speakers today, as well as all of you on the line for your interest in DOE’s Energy Storage Grand Challenge. As we reviewed on May 1, the Energy Storage Grand Challenge, or ESGC, is the result of two premises. First, storage is important, and storage defined broadly— not just batteries and reservoirs, but the portfolio of technologies that achieve storage-like functions. And second, DOE has room to improve in terms of coordinating across offices. The Department has a range of world-class capabilities, and while our objectives may be aligned, our execution may not. What we hope to finalize by the end of the summer is a strategic plan for how to use DOE’s capabilities—everything from convening authority to data-driven insights to the ability to pursue long-development horizons or tackle technology risks.

How these capabilities can be logically arranged to accelerate the storage industry is the major objective of the Energy Storage Grand Challenge. So this strategic plan includes five tracks. First is technology development, which we will go into more detail today. And manufacturing and supply chain, technology transitions, policy and valuation, and workforce development. In short, our goal with the Storage Challenge is to establish U.S. leadership in energy storage technologies or innovate here, make here, and deploy everywhere. Today we want to go into more detail on the technology development track, which focuses on innovate. To maximize R&D effectiveness, it’s useful to have an understanding of how technologies will ultimately be used. So the challenge is to create a unifying R&D framework for everything from sodium-based slow batteries to concrete thermal storage to rocks on railcars. The way we’re doing that is through a use case-informed R&D framework.

So, we start with what benefits the end-user, the home, town, business, or region. Then, with functional requirements, any technology can make the case that R&D will achieve the goals that are needed for each of these use cases. So over the past several months, we canvassed the internal DOE community and got dozens of ideas for how storage could be used in 2030. We’ve distilled them down to six use cases which span the bulk power system to isolate systems and they also range from very well-defined business models and values to loosely defined. Each of these use cases include major drivers, what defines success, beneficiaries, as well as examples of potential cost and performance targets. I will go into detail on each of these use cases now and we will hear more about how these use cases could play out in the real world from our speakers later on this call. So, the first is facilitating an evolving grid.

And so this use case is most concerned with the bulk power system, including generation planning, transmission planning, and distribution as well. Drivers for this use case could include aggressive renewable portfolio standards or transitioning from a world with steady load growth everywhere to more pinpoint investments. The second use case is serving remote communities, and it’s one of the use cases where storage would work in conjunction with other technologies because storage alone doesn’t deliver energy. Applicability of this use case might start with small coastal villages or isolated mountain towns, but U.S. growth in this use case could come with emerging goals like Oregon’s Two Week Ready program where the state is looking to get a quarter million homes ready to survive for two weeks without critical services. While electricity generation isn’t explicitly a part of this now, it could give the R&D community a long-term target for storage functionalities.

One of the largest use cases by market potential is electrified mobility, which includes onboard storage and the related charging infrastructure. Any non-trivial vehicle electrification is going to be a major draw on the grid. Level 2 charging today is around 10 kilowatts. Extreme fast charging is in the hundreds of kilowatts power range. One of the unique performance requirements here could be buffering the spike in demand from extreme fast charging. Next is interdependent network infrastructure, which includes the other infrastructure sectors on which the grid itself depends. With this first or unattended locations, these facilities already use technologies like fuel cells to provide a day to several days of backup.

And one of the things we’d like to look at are: Are there other pathways that could eventually provide co-benefits? Next is critical services resilience, which includes the end uses that are important for life or mission safety. Most common solutions today incorporate some kind of gen set with duration requirements, or onsite fuel derived from NFPA 110. For this use case, hospitals in particular are an area of interest because they count for less than 2% of commercial floor space but consume 4.3% of total energy delivered to the commercial sector.

The examples here show duration requirements for 24 hours to multiple days for facilities depending on their capacity. The status quo isn’t ideal since fuel can age over time; omissions, regs can limit annual run time; and it’s not always certain that the equipment will start up if needed. And so one of the things we’d like to look at are: Are there pathways to economically viable technologies that can provide the same or superior functionality without current disadvantages? Finally, the last use case is divided into two parts: flexibility for smaller end-users, like residential and commercial, and flexibility for large facilities that use or generate power.

There are value propositions and market values today for these use cases, like increased comfort or decreased demand charges. And part of our stakeholder process as well as the policy and valuation track is to draw out what these values might look like in 2030. These six use cases are hopefully broadly representative of what storage could do by 2030. And they could represent a $6 billion to $20 billion annual cap ex market by 2030. Making assumptions about business unit size and conversion ratios, there might be 50 or 60 companies or business units, each with field-demonstrated technologies.

These technologies would span the gamut from bidirectional electrical, chemical and thermal, and flexibility technologies. Each of these pathways would traverse a progression, from foundational science to wide bankability. And for more details on how these pathways might be fleshed out, I invite you to join our webinars next week on the 19th and 20th of May. The purpose of today’s webinar is to jump-start the conversation on how these use cases play out in the real world. What are stakeholder goals, and how would storage technology improvements help achieve these goals? And most importantly, what R&D opportunities exist for DOE over the next 10 years?

To help guide us through some of these examples, I will turn it over to our moderator today, Lola Infante. Lola is senior director of clean energy technology and policy at the Edison Electric Institute where she focuses on market and policy developments in clean and alternative energy resources. Lately, Lola has been focusing on distributed energy resources including solar, storage, and microgrids. And she is here today as a member of the Department’s Energy Advisory Committee, where she serves as vice chair of the Energy Storage Subcommittee. Lola?

Sorry, I was having trouble with my buttons here. So, thank you again for that very kind introduction. And thank you all for joining us this afternoon. This is an important workshop. We have had energy storage in the form of pump hydro and some forms of thermal storage for a very long time in our country. But it’s only recently that we have seen new forms of storage, mostly batteries, really take off in ways and be used in ways that were mostly theoretical only a few years ago.

We have come a long way in large part thanks to the Department of Energy R&D efforts, and as Eric just pointed out, those efforts continue, and DOE is now evaluating its portfolio and ensuring it meets the country’s needs now and in the future. The panel today is composed of a very impressive group of experts that will illustrate with real-life examples the use cases that Eric mentioned a minute ago, and will help us identify some of those needs. With us today we have Sandip Sharma, manager of operations planning at ERCOT. He will open the panel and will discuss how energy storage is helping integrate renewable energy and facilitating operations in an evolving grid. Then we’ll hear from Larry Jorgensen, director of power, fuels, and dispatch at Homer Electric Association in Alaska, and just like Sandip, he will talk about how energy storage is helping develop a more flexible and reliable grid, but in a somewhat smaller and more remote area.

After him, Jordan Smith, senior engineering manager at Southern California Edison, will change gears a bit and will present three very interesting projects combining energy storage and mobility and transportation electrification. Next, Steve Baxley, manager of renewable storage and distributor generation for Southern Company, will illustrate the role of energy storage in helping his company provide energy resilience to critical customers. Let me just note that Southern Company’s territory includes many agencies and offices very important to the country’s health and security. Following Steve, Josh Ruddick, engineer at Eugene Water and Electric Board is going to expand on that notion of critical infrastructure and discuss how it can achieve resilience in other interdependent network infrastructure, such as water in this case. Last but not least, Andrew Maxson, program manager at EPRI, will provide an overview of ways to increase the flexibility, efficiency, and value of customer facilities themselves. And all of the speakers, I think you will agree with me, together they will represent a very comprehensive view of the role of energy storage in our electric future.

So with that, let me now hand it over to Sandip to get us started with a chat on ERCOT on how it is deploying energy storage to facilitate—among other things—the integration of increasingly large amounts of wind and solar power. Sandip, whenever you’re ready, the mic is all yours.

Thank you, Lola. This is Sandip Sharma. Can somebody confirm that you can hear me clearly?

We can hear you.

Okay, thank you. Sandip Sharma, ERCOT operations. A few slides, and I think the story I’m going to tell regarding our call today is, I will give you some perspective of ERCOT grid, and when I say some perspective of ERCOT grid, what I really mean is how it’s different from other interconnection, and how much more renewables that we plan to add in the future, and how much we already have, and how that will determine our future reliability problems that we foresee with higher penetration of renewables in the grid and how some of the energy storage technologies can help mitigate some of those risks. And generally, when I’m talking about energy storage, I am mostly talking about batteries, but some of the things we have done in ERCOT and some of the rules we have written and are writing could probably apply to other technologies as well, but it was mostly with energy storage, with mostly batteries in mind, that those market participation rules were written, and so with that, most of you know that ERCOT is a nonprofit organization.

We’re regulated by Public Utility Commission of Texas with oversight by Texas Legislature. Our big demand as of last summer was 74,820 megawatts, which was made on a hot August day between 4 and 5 p.m. And our maximum wind generation record—instantaneous wind generation record—we made that record last week; it’s about 21,144 megawatts on May 7. And then, most of you know ERCOT has a lot of wind, and so our maximum penetration record is 59.30%—instantaneous penetration—and what that means is on May 2, 2020, at 2:10 a.m., 59% of load was being served by wind. And the wind generation at that time was 19,426 megawatts.

ERCOT, unlike, Eastern Interconnection and Western Interconnection, ERCOT is a single island grid. And what that means is we are not synchronously connected with any other interconnection. We have some DC ties that connects us with Eastern Interconnection and Mexico, and so the renewables present a bigger challenge to us just like it presents a bigger challenge to Hawaii and some of the island grids around the world. With that, as of end of last year, our total wind installed capacity roughly stood at 24,000 megawatts. Right now there is roughly 3,300 megawatts that is not yet fully tested but is synchronized to the grid—that’s new capacity—that is going to the testing process, and that capacity will be counted at some near future point, but in 2020 we expect to add, you know, at least 3,300 megawatts to 4,000 megawatts more of wind installed capacity. And if you look at 2021 and 2022, we will be adding a lot more wind into our grid. And if you look at the queue overall, there’s additional almost 37,000 megawatts of wind in the queue but not all of that will actually become installed capacity.

Just like wind, we also are seeing some good growth in solar generation capacity, and when I say solar here, I am referring to transmission connected solar. These are, you know, large solar farms, and as of end of last year we had roughly 2,200 megawatts of solar installed capacity. This year right now we are in the process of adding another 1,300-4,200 megawatts that’s going through the testing. And by the end of the year, we could be adding another 2,200 megawatts. So, we could be somewhere around 4,500 to 5,000 megawatts of total solar installed capacity by the end of this year, and then a lot more if you look at next few years. Between solar and wind, if we look out into future, we’ll be adding a lot more solar in the future than wind, at least that’s what our queue tells us. And then the state of energy storage; it’s fairly in its early state. As of end of last year we only had 104 megawatts of battery energy storage. This is all batteries, and this year we added about 40 megawatts of new capacity, and then there is more batteries that will be added throughout the year. But at the end of the year, our total battery installed capacity may be as high as 276 megawatts.

And so, with that, I think if you look into next five years or 10 years-type horizon, if you look into like what would ERCOT grid look like in 2025, 2030-type timeframe, we will have a lot more renewables—that is variable renewables, we’ll have a lot more wind and solar, and we will also most likely have more energy storage, you know, added to our grid and from energy storage, even though we don’t see much, you know we don’t see large projections over next few years in those slides, but if we go and look into the queue, there’s almost 10,000 megawatts of energy storage right now in our queue that could be added in next several years.

And so, with, you know, a lot more renewables and invertible resources, you know, one of the things we’ll continue to see is grid inertia will continue to be an issue and even continue to decline. And weak grid issues will be more widespread. Today most of the weak grid issues are fairly local and, you know, those local weak grid issues we expect to be more widespread as we add more renewables into our grid. And so with more renewables, you know, more variable renewables, like wind and battery, wind and solar, we’ll also see, you know, some of the problems that California is seeing with ramping issues.

And so, you know, we have a grid generation mix in Texas, with a lot of fast, flexible gas units, but with more solar, we do expect, you know, higher, especially in the morning and evening hours in the shorter months, and so our dependency on faster ramping resources will continue to increase. Intra-hour variability: we expect intra-hour variability again to continue to increase with more renewables, and then forecast uncertainty for both wind and solar. In the forecast uncertainty associated with large penetration of wind and solar, the risk of error magnitude in terms of megawatts will continue to increase. And the way we see, you know, with more renewables and, you know, more variability into the grid, ancillary services will play an important role, you know, in mitigating those risks and maintaining system reliability. So, that’s the picture that we see as a problem over next five, 10 years-type timeframe.

And where we think, you know, R&D can really help, the first thing is grid-forming inverters. When we say energy storage, I’m primarily referring to batteries; batteries connect to grid using inverters, just like wind and solar. And so most of the inverters technology today that are used to connect with the grid are grid forming, and there is some ongoing research on grid-forming inverters and so grid-forming inverters would help with all the reliability issues and some of the weak grid issues we are seeing today. Flexible batteries would be another thing that can provide a continuous supply of energy for longer duration. Most of the batteries that are connecting to ERCOT today or we already have in our system is, you know, fairly limited in duration. But I think some of challenges of future can be solved only by batteries that are at least, you know, that can hold state of charge for several hours—not 30 minutes or 15 minutes-type batteries.

And so, I think the longer duration of energy storage will be key for ERCOT as we get more wind and solar into our grid. Batteries can also mitigate system inertia issues because, at least at the system level, the system inertia issues are directly related to rate of change of frequency, and the faster response from batteries can actually mitigate your inertia concerns. So, invertible resources kind of will continue to cause inertia problems, but batteries can potentially solve the problem by providing really fast response and help arrest frequency. Because from system perspective, inertia is purely a rate of change of frequency problem. And then today, you know, it’s not very likely that you see a battery and a solar farm built together at a hybrid unit to provide a firm power, but that may be an area where, you know, there needs to be more R&D to see how wind resources and solar resources can be firmed up more so they are becoming more of a constant source of power than variable sources of power that may help grid with reducing variability and intermittency.

And then the last point that I have here in my slide is, you know, some of the tools that we use today where probably needs to be updated, that do not account for all the use cases that energy storage resources can provide. And so from that perspective, some research into, you know, new tools and commercial software that are available today, those need to be updated so that we can more accurately study the energy storage resources capability—specifically batteries’ capabilities. That was the end of my slide. Back to you, Lola.

Thank you, Sandip. Very helpful information, indeed. Now we will hand it over to Larry for a discussion on how to achieve flexibility and reliability in remote communities. Larry, whenever you’re ready.

Okay. Well, thank you. This is Larry Jorgensen, the director of power, fuels, and dispatch at Homer Electric Association up here in Kenai, Alaska. We serve the Kenai Peninsula area of Alaska, so it’s not necessarily large, like ERCOT that you just heard about. We have about 35,000 meters, a little over 3,100 square miles of service area. So, we are not densely populated but we are definitely isolated because we only have a single connection to the rest of the Alaskan utilities, which is the 115 kilovolt tie line.

Some of the other issues that we deal with up here is most of our generation is through natural gas, but the price that we pay for natural gas is about three and half times higher than what you pay for in the lower 48. So, energy efficiency becomes a very critical item for us. So, currently our electrical production is 90% natural gas, 10% from hydroelectric, and to help modernize our grid and to be more efficient with our fuel usage, and to be able to comply with reliability standards, we are installing a 93-megawatt two-hour mega pack battery from Tesla.

We are in the phase right now where we are doing all the site construction work, and the batteries will be in service by August of next year. So our goal is, of course, to have greater diversification of our fuel and energy sources, and to reduce our exposure to high natural gas prices and the volatility of any natural gas market. Also, our board of directors have been very strongly advocating the reduction of greenhouse gases and long-term stability. And currently with our 10% renewables, we are on track to achieve 18% renewables before 2030. The use of a battery system is going to help that greatly.

Our other goal is, because we are isolated, we want to maintain a reliable grid, especially during our long, cold and dark Alaskan winters. People can depend on the fact that they are going to have electrical power, and that they don’t have to resort to some other means to keep their houses warm or to be able to enjoy any activities that they want to engage upon. Some of the opportunities that we also see up here that have yet to be developed that we really look forward in the research and development—the Cook Inlet has been identified as one of the largest tidal resources that’s readily available. We have varying tides from 20 to 30 feet, and, as of yet, there are no tidal generation resources here in this portion of Alaska. There’s been a lot of research and development.

We do have a few items that make it a little bit difficult: The water that we operate in has a high degree of glacial silt, so it has a lot of wear and tear on machines that operate underwater. We also have endangered species that are beluga whales that live in this area, as well as protected species—the salmon that Alaska is so famous for. With those ideas of things that need to be overcome, if we could learn to integrate this type of energy development or tidal energy with energy storage, we could be able to get true renewable production without curtailing any of it due to system constraints and be able to integrate it.

So, one of the things that we look forward in this research and development is not only new technologies that can be developed to make use of these renewable resources but also better ways to integrate the batteries and make use of them in our system—whether it be through some of the ideas that Sandip explained for ERCOT, or whether it be through just better integration to make that sure we don’t have any issues that causes us frequency deviations or curtailment of those sources. So, that’s pretty much in a nutshell, hopefully it gives you something interesting to look at. I will turn it back over to Lola.

Thank you, Larry. Very interesting insights and perspective for sure. Thanks for that. Next, we going to hear from Jordan from Southern California Edison for a few examples of the very important topic of mobility and transportation electrification. Jordan?

Thanks very much, Lola. And let’s see if we can get the slide situation—very good. So, I am a consulting engineer at Southern California Edison, so focusing in on creative modernization and technology to take us to the next stage. So, a little bit about Southern California Edison. Here is our service territory here. Fifty thousand square miles, 5 million meters, about 15 million residents. A little bit about the infrastructure: about one and half million poles, 700,000 transformers, 103,000 miles of T&D lines, and just setting the stage here. A lot of our activity is focused on policy, as folks have heard about, and I’ll talk a bit more about that. But priorities in safety and reliability; distributed energy resources; and integration of renewables.

So, as part of that, electric vehicle charging is a large focus. And I will talk about Pathway 2045 here next. So, Pathway 2045 is a study and resulting white paper that was developed by Southern California Edison to basically provide the proposed execution of a plan to reach the state’s goals for carbon neutrality by 2045. And it’s a successor to our Clean Electrification Pathway 2030 plan, which was published earlier. I should’ve had a footnote here for where you can get these reports, these plans, but they are available on our website. So, as part of that plan, we’re anticipating a 40% increase in peak load as fuel switching occurs to electricity. Anticipating 80 gigawatts of new generation (and that “3” there, I apologize for that, that was referring to the footnote I talked about earlier). Anticipating 30 gigawatts of new energy storage as part of the new system, so 75% of vehicles will need to be electric by that point. And so, you know, just for reference, I don’t know what we’re looking at today as far as population per vehicle and how that’s changing, but, you know—just assume one car per person for now and so that’s about 50 million and 75% of that. Seventy percent of buildings will need to be electrified, so moving to electric-saving water heating, and two-thirds of medium-duty trucks, and one-third of heavy-duty trucks will need to be electric at that point. So, now this presents potential challenges to the utility to provide this level of service, and so my part of the organization, we’re actively involved in figuring out the plan to provide that service.

And so, part of that will be a lot of physical work, as pointed out earlier, but also a lot of technology. We’re anticipating a lot of technology needs to help us here. And so a lot of what we will demonstrate—and need to demonstrate as far as technology—is conducted within the EPIC program. And some of you may be familiar with this, but just very briefly, it is a ratepayer funded program for electric system RD&D and focused to meet the state’s goals for greenhouse gas reduction.

And so the R&D portion is actually managed by the California Energy Commission and then a portion for demonstration purposes is managed by the state’s investor-owned utilities, such as Southern California Edison. So as part of that, at the IOUs here at SCE, we’re in Tranche 3 of three separate 3-year tranches. And in this tranche we have a total of 26 projects that are just launching in various stages. And within that group, there are three transportation electrification projects.

So, I’ll briefly overview here. So, the first one we call distributed charging resources, which is sort of a play on distributed energy resources. But the basic concept here is, and I laid out the need for vehicle electrification, fleet electrification, and so we anticipate the need for a lot of high-powered chargers out there. I think the state has estimated the need for around 250,000 public chargers. And so, we’ll need to plan to provide service for those chargers.

So, the idea here is: would we be able to mitigate that projected peak system impact, which could impact feeder capacity, power quality, and those types of things? And so could we mitigate that with integrated or associated energy storage systems? And so there’s a few twists here beyond what you might expect a proposed commercial product to look like, which some are emerging here. But the twist here is that the energy storage system is owned and operated and managed by the electric utility. And so we can use that battery, not just for managing the peak demand of the charger as would be done traditionally from a customer perspective, but we can use those storage systems and associated control systems connected to our grid management system to manage the local distribution system and provide a lot of functions there.

The next project is a vehicle to grid, or V2G project, and a lot of people have heard this term, and it’s pretty exciting and pretty novel. But what we need to do now is get to the stage where it can be sort of actualized and put into a real utility integrated function there. And so there’s a lot of technical issues involved, a lot policy issues involved, and this project is going to help us work through the technical issues to figure out how this can and should all be done.

So, two different architectures here just on these very simple diagrams: typically what we refer to as AC, or onboard inverter architecture, and then DC offboard inverter architecture, and both have various technical characteristics and issues to work through for general utility interconnection purposes. And then beyond that, it’s a matter of demonstrating what the systems need to be able to do and where they can provide value. So, there are four specific areas here that we’re looking at I won’t go into detail on. But one involves light duty with major OEM. There’s a school bus segment and a transit bus a segment.

And finally here, this is quite a large project and a large concept here that we call service center of the future. And this cartoon here just kind of lays out the various components, but the original idea was looking at our own service centers—which is basically where we house all of our trucks and crews—distributed throughout that 50,000 square mile service territory, that go out and maintain the system. And so there’s a couple things coming together there. One is that we are working to electrify our own fleet, and then how do we do that in the most efficient, cost-effective manner, and set it up and run it and operate it? But also, looking at where all of those service centers are located and whether we can use those systems that we deploy to manage the electrical system where they’re located. So we may have a lot of DERs, we may have challenges in the local system. DERs may include PV or EV charging, what have you. And that’s the general concept.

As we progressed on and got to the point where we are now, which is basically moving into execution, we found that we pivoted to a commercial customer and so we are looking at commercial fleet. Things are moving a little faster as far as the vehicles, but the general concept remains. And so what we have here is—from the meter, utility owned, operated energy storage system, fairly large, at around 2 megawatts, around 4 hours—and we are looking at supporting a fleet electric vehicle operation that theoretically could reach on the order of, say close to 20 megawatts. And the idea here is that we can serve that with technology at a much more impactful level and something that would allow us to use these techniques at other fleets to basically provide service with less cost, less impact. So just a few of the high-level objectives that I have laid out here—and I’ve described this pretty well already, and shown in the diagram—but basically what we’re looking at is a large fleet with a lot of electric vehicles at high power where we’ve got a building electrification component integrated in; a building energy management system integrating with a site energy management system or site controller, which integrates with the chargers; the building; and some submetering element for data and control. Now that system also integrates with our SCE Grid Management System externally and the large grid side from the meter battery.

So, obviously we’ve got to look at managing fleet operations and making sure the vehicles can operate, do their job, but optimize, minimize cost, while at the same time using that system to manage the grid. And so just a listing here. A few of the use cases that we’ll be demonstrating here, and I won’t walk through these, but this just lists a few of the steps involved in these use cases and I’ve kind of talked about these already, but there’s obviously benefits that may flow to the customer as far as rate management, and there are benefits that may fall on the grid side, such as voltage support, and some may cross over both, such as a resiliency, as we call it, or power off contingency operations. So, that’s all I have. I will turn it back to Lola.

Thanks, Jordan, that was fascinating—really the way of the future. I’m going to hand it over to Steve Baxley of Southern Company for his experience now on how to enhance the resilience of critical facilities, another really critical topic. Steve?

Thank you, Lola. Afternoon everyone, I am Steve Baxley with Southern Company and I work in our R&D department within Southern. I lead the group that is responsible for renewables, storage, and distributed generation within Southern. So today, first I’ll introduce Southern Company a little bit. Many of you guys may be aware of Southern Company. We’re a utility headquartered in the Southeast, but not only located in the Southeast; we’re really a nationwide utility now that provides energy services across the U.S. Our regulated electric utilities focused in the Southeast are Georgia Power, Alabama Power, and Mississippi Power. But we have assets across the U.S. through our wholesale subsidiary Southern Power, and through our entity PowerSecure, that plays a good bit in the distributed market and installation of microgrids for things like critical infrastructure support, particularly for businesses that need additional resiliency. That’s a little bit about Southern Company.

Within our electric utilities, we have about 44,000 megawatts of generating capacity. So, not as big as ERCOT but still a good size utility here in the Southeast. And we are located in the Southeast where, just like many of you guys depending on your location in the country, we have various types of frequent environmental stresses or threats. In particular, we have hurricanes and tornadoes a good bit in our region. We’ve just been through in the past couple of years some pretty large hurricanes; the last one was Hurricane Michael that hit the Panhandle of Florida. At the time Bell Power was still part of the Southern Company. We had an outage that lasted for those impacted areas for about two weeks before we could get the system up functioning, back to serving a majority of those customers. We also, just over the past few weeks, have had a number of tornadoes—depending on where you are, you may be aware or not—that moved through the Southeast that impacted a number of our customers.

So environmental stresses and threats from weather events are something that we deal with on, you know, a very frequent basis and it’s something we are accustomed to. And we have gotten really efficient at dealing with those situations. But we all are always looking for how we can improve our response times, how we can continue to meet our customers’ needs throughout these events. In particular, critical customers, critical services like emergency services and government facilities. I think we are all even more aware during this pandemic of the need for critical services such as hospitals and emergency services that are supporting life and health and safety throughout this time.

So within Southern Company, we have within the southern footprint of our electric utilities—we are blessed with some great customers in our military customers. So, we have 22 military bases or facilities within Georgia, Alabama, and Mississippi—facilities like the Kings Bay Navy Base in Georgia that houses some of the nation’s critical nuclear sub fleet. Or the Air Force base in Biloxi that houses the squadron that responds to—sending planes out into hurricanes, measuring those weather events and updating the nation on what’s happening there. In addition to the military bases, we also have some critical government facilities like the headquarters for the Centers for Disease Control in Atlanta. The FAA as well. So, lots of really critical services within our footprint. That is of most importance for us to serve those customers in the best manner that we can, and to keep them running in times of critical need.

The next slide here. So I would like to mention, talk through quickly, one of our projects that we have, and while these aren’t at critical infrastructure sites, they are in the same vein of using storage and other distributed assets to provide resiliency and energy services to these two communities. So, these are two projects: one in Georgia and one in Alabama in Birmingham—the other one in Atlanta in Georgia—that are what we have labeled as smart neighborhoods. So these smart neighborhoods, there are some key differences between the two of them. The first one that was established was the one in Birmingham, Alabama, there on your right, which consists of 62 single-family homes. Those homes are fed by a microgrid that is utility owned. So, Alabama Power owns that microgrid and it consists of 330 kilowatts of solar, 680 kilowatt hours of storage, and then also a 400-kilowatt natural gas generator. And that microgrid asset is integrated back into the home so the whole neighborhood can island from the larger grid itself in the event of an outage and serve that community.

Some of the key things that are unique about that neighborhood as well is, in addition to the microgrid serving the needs of the community, the microgrid is integrated in with the home, so this is a project that we’ve done in conjunction with Oak Ridge National Labs, with EPRI, with the U.S. Department Energy, Building Technology Office, and not only having an asset that, you know, can provide energy with an island situation but also look at both from the load side and the source side. And so, we’re using smart appliances in the home to manage the load. And so in a critical event we can—or if we see a peak coming, if we want to shave a peak for the larger grid—we can pre-cool the homes; we can shut hot water heaters off, so we have hot water heater control; we have control over the ACs in these homes. So we can manage the loads when we see events coming or if we know a storm event is coming. We can charge the battery in the microgrid. So, doing that all together in an integrated fashion, having the intelligence behind it to see when events are coming and to prepare for that is a key part of the learnings that we’re gaining from that neighborhood.

Moving over to the neighborhood in Georgia. One of the key differences between the two—the Georgia neighborhood also has smart appliances, has the ability to control the loads in the home. The difference is the assets, or the energy-producing assets, are located on the individual homes, so these are townhomes in Atlanta. So, they have 3.6 kilowatts of solar and 20 kilowatt-hours of storage located within the home itself. Again, the loads in the house are integrated back in with the solar and the storage to help manage that in the event of an outage or an event coming, to prepare for that.

So, some of our long-term vision and goals for this critical service-resilient space is to do that—is to maintain critical services for our key customers that require service during these times: military bases, communities, campuses, government healthcare facilities, during an extended period of outage. So, understanding both what their load looks like, how you can manage the load on their side of the meter, but also provide these resilient services from the utility side of the meter. On many of these installations, military installations, we already have assets such as solar facilities that are supplying renewable energy to the grid. But for most of those cases the infrastructure is not there and the communications and control and intelligence is not there to island that and use that renewable asset in conjunction with the other assets around the base such as, you know, diesel gen sets that are there for backup.

So, we see a vision in the future of integrating all those together to provide not only benefits to the grid at large, but also during times of critical outages and critical needs, specific benefits to these critical infrastructure sites such as military bases or college campuses or hospitals. So, integration of these distributed resources in a smart manner to support during these times, we think, is the vision for the future. And also, using these assets again, not only for support of that particular site but also supporting the grid, and recovering from disruptions from natural disasters. So can we use these assets for a coal load pickup, can we use energy storage to help support that?

We think some of the things that are key to do that are things like open, standardized interface with storage technologies to be able to control and integrate that at various points of our connection on the grid. So whether you’re at the military base or on the distribution level, or if you have a large PV that’s on the transmission level, or even down to a critical commercial customer that has a need for additional resiliency, being able to tap those resources and control them, see them, for larger grid disruptions, is going to be important. If you’ve ever ran or ever implemented a storage project, you know that some of the key issues that you always run into in this phase is the integration of controls and how do you adequately control that, see it, and manage it. That is some of the challenges that we still face.

And then really, you know, these last two working together—I mentioned this a little bit ago—the co-optimization of storage with DER and managing from the demand side, but also the source side, and integrating those two together to help facilitate, you know, longer-duration outage events. To being able to shed load at particular times, and then use your DER in conjunction with being able to flex on the demand side, will help you extend the duration for which you can cover these outage events. And then, you know, intelligent dispatch, we mentioned this a little bit too.

Just having the smarts to be able to understand where your energy storage assets are out there, how you can couple that with, you know, phasing in if you’ve ever had a wide outage on a distribution sieve, how you bring that together with the assets you have out there to bring the system back up. Some of the R&D. Where can R&D help? I’m an R&D guy, so you know, I love this slide because I think we can do a lot of help, and have a lot of work to do in the future to continue to advance energy storage to help us have a more efficient, robust grid.

So, you know, some of these are kind of core fundamental things we think that still need work. One is just to continue cost-effective technologies with the sufficient storage duration and capacity. So if we are talking, you know, being able to support a facility for a longer-duration outage that’s more than a few hours, the technology at this scale is not quite there yet. So, longer-duration storage; has the capacity; that is cost effective, is going to be key to enabling the deployment of this type of technology. It goes back to our Southern Company mantra and our mission of clean, safe, reliable, and affordable. So, we need all of those. We need safe storage as well.

We’re all aware of some of the issues, particularly around battery energy storage and the fire concerns that have been in the news of late there. And so for us to be successful in this avenue, and utilizing energy storage, whatever the technology is, we have to have the clear guidance and the clear knowledge to be able to do that in a safe and effective manner. If we’re in an event where we’re recovering from a storm or a natural disaster, we don’t want to add to that by having our own safety issues to deal with, with storage technologies. And then reliability.

As Eric mentioned when he was introducing the talk today, he mentioned diesel engines, and, you know, when you go to turn them on they’re not always “there” if they have not been maintained and kept up as they should be. And we don’t want the same to happen with storage. And so, as we’re early in the space, being able to understand what are the reliability issues with storage, what are the types of maintenance protocols that we need to maintain to give us the type of reliability we need so we can count on that asset when we need it.

So, I think we still have a lot to learn there about operations and maintenance of energy storage and the reliability. I mean, something simple for battery storage, the least reliable aspect of many of those systems is the air conditioning control.

And so, those systems aren’t built to what I would call a utility reliability standard. But yet they’re a critical link in the operation of these systems. So we are relying on something that has potentially a weak link there, and we need to address that and understand that. Then again, you know, the systems controls that we already talked about a little bit and the wider integration, so having plug-and-play where energy storage becomes plug-and-play, where we really can plug it in and control it and see it, no matter the point of interconnection on the grid. And then the appropriate tools for sizing storage to understand how we can support these critical facilities and the loads.

And finally, rounding it out, so these go to together at the end, is optimizing and understanding the use of these systems in addition to providing critical services. So, you know, I know, like many of you, whenever you look at energy storage and where current costs are, for one particular use case and one application, you go, well, this is a challenge to do this for just this one application. So, this would be a challenge to do this just for critical service resiliency. But if we can stack uses, if we can optimize the use cases and build them together so that battery is not just sitting there for a critical service that you may use, you know, infrequently, but it’s being utilized to make it cost-effective for other services during normal times of operation, then I think integrating those uses together is going to help further the adoption of these technologies for critical services and resilience. All right, I believe that is my last slide as well, yes. Thank you.

And thank you, Steve. Another fascinating presentation. This is such an important topic. So, thank you so much for your leadership on this. We’ll now hear from Josh from Eugene Water and Electric for an equally important topic: the protecting or enhancing the resilience of major interdependent infrastructures. So, Josh?

All right, thanks, Lola. Yeah, I’m Josh. I work in the systems engineering group for electric transmission and distribution at EWEB. EWEB is Oregon’s largest customer-owned utility. We have 94,000 electric accounts and 62,000 water accounts. So, today I want to share about a recent project that EWEB carried out with a partnership in support of all the parties listed on that slide—what we call the Grid Edge Demonstration Project at Howard Elementary School. It spans several years beginning with, you know, internal conversations leading to external conversations, grant writing, grant awards, contracts, and construction and beyond. So, EWEB has its own engineering teams in water and electric and in generation.

We’ve done many projects, but this type of project is really new to us, and so we needed plenty of help. So, we’re really grateful. A portion of the funding came from the Oregon Department of Energy in a grant that included the components listed on the slide. There are more use cases there listed in the site on the internet at one time, but the idea is that you could use it for those purposes, or as Steve mentioned, you’ll be able to stack some of those. Plus, it’s helpful to list as many as you can when you’re applying for a grant and show diversity.

The project, according to the grant, was going to include installations at multiple sites and each with its own unique purpose. But as each site was evaluated, the best fit ended up being the newly built Howard Elementary School in Eugene. So, it was agreed that we would install it there. And the fit at Howard Elementary was good for several reasons. One of the biggest reasons was that it met some high-priority strategic goals for EWEB as it relates to resilience.

The two top priorities for the organization were emergency preparedness and disaster recovery, and electric supply resources. The utility was interested in planning options for the electric resources and the battery storage system can support that for sure. EWEB is also preparing for emergencies continually and those emergencies that affect the electric distribution system from, you know, smaller storm events that we’ll get in the valley here all the way up to something as large as like the Cascadia earthquake scenario.

So, the ‘W’ in EWEB is for water, so we’re also a water utility. We take pride in delivering quality drinking water to the community. As we know, drinking water is key. The water utility is a large customer of the electric utility and it’s susceptible to electric outages. This interdependence between the electric and water distribution system comes with vulnerabilities. Disasters can affect water delivery from the electric distribution side in the form of electric disturbances, you know, cutting power to the water treatment plant or to pumping stations. Other disasters could be like contamination in our single water source—something like a chemical spill from a truck or something on the highway next to the McKenzie River where we get our water.

So in light of that interdependence between water and electric, the Grid Edge offers another way to deliver water to the community outside of the traditional distribution system. And it also satisfies the need for an alternate water source in the form of a well at the Howard Elementary site. In resilience, or an islanded mode, the battery system powers the local water well pumping. And the graphic here is from a previous campaign just to prepare the community for emergencies with those subsidized water jugs. The goal for the utility became five sites in five years.

In the process of moving Grid Edge forward, the community connections grew and so did the viable sites, like Howard Elementary, for supporting resilience in the community. EWEB already has a long history of supporting energy management, including solar energy. Several schools have solar electric installations from incentives by EWEB.

This new effort for Grid Edge builds on those relationships and helps strengthen EWEB’s good standing with its customer-owners. The map shows here shows part of EWEB’s service territory and I know it’s hard to see but there are some spots there that identify projects that we’re pursuing—some green dots with water that’s been identified and available, and then some other spots, it’s not quite as developed, but it shows kind of the direction we’re heading there. It was important to locate these sites near residential areas.

Schools and community centers are already set up for accommodating larger groups and traffic flows, so they could be used for shelter, you know, water distribution, food distribution, communication, electric charging stations. Depending on how the energy is managed, the battery energy storage system, the BESS, at Howard could provide two weeks or so of water pumping with the photovoltaics included, which with the building where we had, it could last even longer. In the top picture here is another tool EWEB developed to help the community during water emergencies. That’s a tree where it can be delivered to the problem site for short-duration outages.

Actually, we were able to use this, you know, a couple of hours or an hour away in the city of Salem during a toxic algae bloom just to support that community there. And that worked out really well. The bottom picture is actually at Howard Elementary, right in front, and it was during the demonstration event. There’s dozens of water connections right there for community members to fill their water jugs or whatever. So again, the battery system powers the pumping from the well that EWEB drilled as a part of the project, and all of that’s stored onsite and ready for an emergency.

So another use for battery storage systems is to provide electric bill savings. A requirement of the grant is to support research for battery energy storage systems. This includes battery performance metrics, you know, charge and discharge rates, a bunch of other different things. During non-emergency events, the batteries can provide bill savings to the customer as well as opportunities for savings to the utility. The storage system at Howard Elementary is behind the meter. So, the primary use case for them would be peak demand shaving, as that graphic kind of demonstrates. In this case, the battery system would charge during the low building loads, and discharge during high loads; it flattens the low profile out for the building and reduces the customer’s peak demand charges for the month. EWEB doesn’t have time of use rates, but this could be another way to reduce the bill by charging, you know, during low-energy pricing and then discharging on the other side.

Currently, EWEB is not at a point where we are ready to operate these batteries to benefit on the utility side, but we could see a time in the future with maybe more energy storage installations in the community that could be aggregated and dispatched together in a strategic way while maintaining those resiliency needs. So, every project has its own challenges and Howard is no exception. Having many partners is great, you know, for getting these projects done, especially when it’s not normal work for the utility. But more partners also add complexities and sometimes competing interests.

So here’s a short list of challenges we experienced in this project, all of which could be improved with this grant and R&D. Number one, locating a battery system owned by the utility but behind the customer’s meter adds complexity to the performance tracking. And so, any bill credit arrangements are kind of tougher to track on that, too, because the school was hosting the batteries. Number two, the BPA also has its own metering requirements to account for in the systems larger than 200 kilowatts, so we had to make sure we provided that. Number three, it’d be nice if you didn’t need another set of batteries to get it started during a blackout. Four, we ran into some controller issues that caused a problem for connecting the photovoltaics during island conditions. We’re still working on that one. Number five, commissioning the system was a bit rough and there were some gaps that could have been avoided with better understanding and more experience. Number six, when you’re looking to use someone else’s land in the city to install these battery source systems, it’s nice, you know, to control the size of it. So, if there are ways of doing that, I know there’s other fire concerns in that, but still it’d be nice for real estate purposes. Number seven, we found that controllers are expensive, particularly for these smaller installations; it was a percentage of the total project cost. The prices are coming down, but we ran into some problems in that area. This controller here would allow better integration—another thing Steve mentioned, just the integration issues between components—but including, make sure solar was a part of this.

So, what could we do with more or improved storage? We could continue to develop what we call our resilience buy-in in the city for our critical customers and for the community. We could expand on this five sites in five years goal. And we could also access probably other energy markets to save our customers money. All right, this is an image showing our little installation there. The blue container has all of the water parts—you saw that earlier picture. And then the white enclosures on the right, these are twins; there’s a total of 500 kilowatts there. You’ve got the batteries in the back and then the two inverters in the front. The pump controls are right in there, too, behind it all. And then the well itself is just out of frame to the right. Thank you.

Hi, Josh. I have to say, I learned a lot from your presentation. Thanks again for agreeing to come today. For our final panelist I’m going to hand it over to Andrew, from EPRI, for also a fascinating discussion about ways to enhance the flexibility, efficiency, and value of electric customer facilities. Andrew, take it away.

Thanks, Lola. And it’s great to see we’re actually ahead of schedule. Some great presentations from colleagues, and I really want to thank the team that put this together; it’s been very well run and very well organized, so great job. It’s nice to see friendly colleagues online, and hopefully everyone’s been safe in these trying times, and hopefully we can all get through this together. So, my name is Andrew Maxson and I work for the Electric Power Research Institute.

I will be covering the case from the facility flexibility, efficiency, and value enhancement. And just to crib from the notes that were passed out on this that the goal of these use cases is to describe a set of applications that could be enabled by energy storage. And in this particular case, it’s improving the flexibility of an energy-intensive facility like a power plant. So, EPRI is a nonprofit that does independent research covering all aspects of power generation. EPRI has been doing research on energy storage for some time now and is doing work on all the different types, including chemical, electrochemical-like batteries, mechanical, and thermal energy storage—the latter of which will be a focus of this use case.

We at EPRI cover various aspects of energy storage including smaller scale energy storage, distributed generation, larger scale things like pump hydro, integration with renewables, dispatch modeling, transmission, operations and planning, and larger scale or bulk energy storage, and bulk energy storage in particular has become a growing focus for the power industry with the growing rise in intermittent renewables. So, this slide gives a brief description of the use case.

The growth in variable renewable energy is causing many thermal plants, and by thermal plants I mean ones that a produce heat for a useful purpose, including power, to operate differently than designed with reduced capacity factors and increased dynamic operation with more ramping and start-stops. This increases the maintenance and potentially environmental issues on these facilities, while reducing efficiency and lifetime. In turn, their overall value decreases, pushing them toward less use and potentially even retirement, which we’ve seen a lot of in this country. Which for plants with rotating assets, losing these can contribute to grid instability by a loss of real system inertia.

A potential solution to this: if you integrate thermal energy storage directly to these facilities to allow them to run more at full load as they were intended to run, storing energy when it’s not needed and then providing it to the grid or as heat for industrial processes when it is—this improves the value of the facility, and for the case of a thermal power plant, maintains dispatchable synchronous power on the grid. This schematic shows the flexibility of thermal energy storage. So, heat can be obtained from a variety of sources, obviously fossil, gas and coal, nuclear, concentrated solar, or even from electricity through electrical heating.

So while there are a wide variety of different types of thermal energy storage systems, they all have things in common. They all store heat that can be used—the heater working fluids such as steam or air or even an uncommon one, but one that could have higher efficiency and is super critical, CO2—to produce power, or be used to deliver heat to an industrial process, or for the purposes such as steam heating for communities.

These thermal energy storage systems are very good at retaining heat, often with losses as low as 1% per day, and can provide large amounts of energy (gigawatts, thermal) for durations estimated to be up to 48 hours in some cases. Just a couple of pictures of some examples of several candidate thermal energy storage systems. And this is certainly not all-encompassing; there are numerous other types being developed. There are literally dozens that are being introduced annually. So, sand and concrete on the left are examples of using a cheap thermal media for energy storage to reduce system costs. Molten salt, pictured on the bottom, has been applied commercially on consecrated soil at power plants in several regions and is being investigated for potential integration with fossil and nuclear power plants as well. And pumped heat energy storage is a reversible process that uses heat to drive an internal power cycle to produce power when needed, and when not, it works in reverse to compress the working fluid to generate heat for storage.

In general, thermal energy storage systems have relatively high roundtrip efficiencies, ranging from 60 to 85 plus percent; are safe; have for the most part few environmental issues; and are relatively simple—they would be well recognized by somebody working at a power plant as many of the components would be familiar to them. And compared to lithium-ion batteries, focusing on longer durations, they have smaller footprints on a comparable basis, as much as four times smaller. They provide “real” system inertia, and at least on paper, have lower costs, and we’ve tracked in some cases a system as being projected as four times cheaper than a lithium-ion battery. However, they are still relatively immature and most have been demonstrated only at a smaller scale but not at scales of relevance. So it has a lot of R&D left to be done on these systems.

So, the following slides provide a visual depiction of a typical use case for integrating thermal energy storage to a thermal power plant. For this example, the facility has three units that are now running at 25% capacity factor, with frequent ramping and start-stops. So, this would certainly be something that would be familiar to coal power plant operators in this country. To apply thermal energy storage in this case, you could retire two of the units, and the power islands are retained to be used by the thermal energy storage systems.

So, only one unit remains in operation as the primary energy source, and this now operates continuously at 75% capacity factor, so, closer to its nameplate with improved performance. So, when demand is then low on the grid, the plant charges the thermal energy storage system and there is no output. And then when demand is high, power is provided by the operating unit, and potentially you can discharge the thermal energy storage system at the same time, and hence be able to produce output that actually exceeds the single unit’s capacity. So, this provides, in effect, peaking capabilities which can be potentially used at opportune times. The facility hence becomes more valuable and reliable. A dispatchable power plant is kept available to provide grid protection.

So, this is something that EPRI’s been investigating and a variety of different thermal energy storage systems could be applied in this manner. So, the long-term vision and goals for this use case are to have cost-effective, longer-duration thermal energy storage systems in various forms available before 2025 to be coupled with operating thermal facilities. And then in the future, if the facility can no longer provide heat, such as may be the case with the fossil power plants, particularly coal in a low carbon world, then the facility should be able to be converted to electrical heaters to extend the life of the plant and allow it to continue providing low-cost dispatchable power with system inertia. The facility will be more efficient, cleaner, last longer, and ultimately will have more value.

So, on the final slide here, so what are the technology needs and opportunities? So, this is really reflective of any technology, and some of these thermal energy storage systems are more advanced than others. But in general, to advance technology concepts that would be needed to fulfill this use case, there are three critical pathways for R&D. Technology advancement, assessment, and demonstration. To advance technologies, design reviews of the system, and in particular how it’s integrated to a thermal plant to optimize performance and reduce cost, should be performed, and when needed, depending on the maturity level of the technology, smaller scale testing and component testing, particularly of more novel, more advanced systems. In parallel, technologies need to be assessed to understand their potential costs and performance and identify any gaps that must be addressed and the cost of doing so for the technology to advance. So based on advancing these up the maturity chain and comparative assessments, technology could then maybe selected to focus on those that should be demonstrated at relevant scales and real-world environments to be able to advance on to commercial readiness.

Having spent a lot of time in the power industry, it tends to be a very conservative industry, and there’s very few that want to buy first and those that want to buy first want to make sure that they’ve seen the nuts and bolts on the ground in an actual operating facility that they have some belief in and have seen that it works. So ultimately the value of these concepts and where and how they can be applied, along with a developed supply chain to create competition and reduce manufacturing costs in time, will also be needed because we envision that these systems will be prevalent in the coming world. This all needs to happen relatively quickly as intermittent renewable penetration grows. In some regions, such bulk scale longer-duration energy storage is already needed. There are areas in Europe that have over 30% variable renewable energy already and they’re already installing longer-duration, larger scale energy storage. And in others, in many regions of the U.S. for example, it will be required as low carbon goals will continue to drive more and more solar and wind.

So, in this time period, between now and when that happens, capitalizing on existing infrastructure to maintain dispatchable, synchronous power generation is critical before it’s lost. So, much of this R&D will require public funding to be advanced, with DOE’s Energy Storage Grand Challenge being a great vehicle and a very common one to accomplish the goals of this use case. And with that, I’ll turn it back to you, Lola. Thanks.

Thank you, Andrew, very much. And thank you to all of our panelists today. I think all of these presentations clearly do show the importance of energy storage in helping us be able to have clean, safe, reliable, resilient, and affordable grid of the future. The speakers have shown that energy storage can be a critical tool for managing the grid and for increasing resilience in many different ways and circumstances. Energy storage can really be a key to unlocking the future that we want. In a second we’re going to move to questions using the chat. Please reference the speaker or topic when you submit your questions and we’ll get through as many as we can.

Before I turn it back to Meredith to manage the Q&A portion of this workshop today, let me ask one question to our panelists while folks finish submitting their questions: You have all described how you’re using energy storage and energy storage can be an effective tool in helping you achieve your goals, and you have explained how R&D can help, but digging into that question a little bit more from an R&D perspective, is the state of the technology or its cost-effectiveness sufficient? It’s another way of saying that: is “business as usual R&D” meeting your needs? Is there anything else or anything in particular that you would like to highlight that you need in order to achieve your goals? And how can DOE help with that? Do any of you want to answer that?

I can step in with a quick one. This is Jordan Smith.

Thank you, Jordan.

So, I mentioned that we have about 26 projects moving forward at various stages. We have a lot of experience with lithium ion batteries and so that’s fairly well proven at a utility system distribution level, and so for those transportation related projects, that’s what we intend to focus on. But we do have a separate project, one of the others that I didn’t speak about, which is focused on non-lithium ion battery technology. And so that need arose out of the potential concern of going too far down a certain path, and we want to make sure that we have a good understanding of alternatives, as use cases or requirements can change. So beyond lithium ion, in this category there’s a lot more uncertainty and so I think that’s an area where, you know, the DOE can help and industry can help with coming together and helping to sort of identify new technologies that can fit those requirements.

Thank you, Jordan. Anyone else would like to offer thoughts on this?

Yeah this is Steve Baxley. I would just echo that. I think lithium has matured nicely but there are still some, I think, uncertainties there, particularly around safety, improvements around integration that we can make in standardizing that for sure. But beyond that, I think, as Andy mentioned, the need for longer-duration storage as we continue to evolve the grid and get more variable generation on the grid, the need for longer and longer-duration storage is going to come into play, and we need additional options there. When you’re geographically constrained with Ks or pumped hydro, I think having other longer-duration options, like thermal storage that Andy discussed, and others is going to be more and more important.

Yeah. Anyone else would like to jump in here before we turn it over to Meredith? No? All right. Well with that, Meredith, I’m going to hand it back to you for more questions from the audience.

Wonderful. Thank you, Lola, and thank you to all of our panelists. We are going to open for questions now. You all have done a great job following instructions and we have a number of questions already submitted, but please continue to send those. We’re going to try to get to as many as we can in the next 29 minutes that remain here. So, I’m going to start with a question for Sandip. Are you able to go beyond 59% wind without the use of synchronous condensers to those business…inertia?

Sure. This is Sandip. And so, the 59% at systemwide level was purely the function of total wind in the system at the time of the minimum load—2 a.m., early in the morning. Now, in my opinion, I think we can go higher than 59% without synchronous condenser. There are some synchronous condensers in ERCOT, primarily in our Panhandle area, primarily to address the local issues. But I also want to caution that going higher than 59%, 60%—as we go higher we’ll also be limited by the local issues that today prohibit a higher amount of, you know, wind transfer from regions where the wind pumps are located into the load center.

So there are already a number of transfer limits in our system that prohibit any higher amount of penetration of higher generation from wind and solar in some cases, and so, you know, maybe going about 59%. But I don’t expect us to be going, you know, too much higher than that number. There are local issues that will limit how much those resources can actually produce.

Great, thank you. Just very quickly, we want to let everybody on the line know that we will make this presentation available. We will be posting it to the Energy Storage Grand Challenge website a little bit later. It takes us about a week to get this ready along with the transcript of the recording as well as the slides. But those will be available for folks. Jordan, a question for you: What role do you see long-duration energy storage playing in electric mobility?

Well, I think it’s going to have a large role. You know, when you look at sort of the full electrification scenario—and there was another question there about—I don’t know if you’ll get to that as well, but there was another question there about kind of, how in general such mobility controls might be used instead of or to supplement energy storage. And I think they’re both together there as potential options, and the demonstrations that I went through are going to determine how the tools that we think we’ll have will be used to realize that value and to what extent. But in general, when you look at—and I mentioned the 250,000 public charging stations estimated needed by the state of California, and you kind of spread those out in anticipated locations on the grid and then you superimpose those on current grid characteristics and line them up with concurrent p-coding, etc., that I think that there is going to be a definite need for energy storage to manage those sources, and taking into account the characteristics of the charging load which tends to be quite “peaky.” So, I think with energy storage, it’s going to be a valuable tool there to lessen the costs and impact on the grid and integrate all of those electric vehicles.

Great, thank you. Steve, and maybe Lola you want to jump in on this one as well: Large grid storage and microgrid storage seems to change the economics of utilities by introducing a new player—sorry—a new player from the perspective of investment operations. Are there considerations among utilities and regulators that by 2030 energy storage providers might be regulated separately from distribution, transmission, and generation?

I’m not aware of any considerations that they will be separately regulated. I know, obviously, there’s FERC Order 181 that talks about—if you’re in that type of market—opening those markets for energy storage providers. But I’m not a policy guy, so Lola may be better suited to answer this than me.

Yeah, thanks. I don’t know that it’s a matter of regulation; where the conversation really is, is in the classification of energy storage because it can act as generation, transmission, distribution, or load at any single point and sometimes at the same time, right? So, for policy purposes and regulation purposes, there is that need to update existing rules to allow for that—I don’t know how to say it but—ability to perform several functions, right? So, I think, so there’s the federal FERC level classification for participation in markets and for accounting purposes, and then there’s the state level classification of storages as well as the other assets, and I think that is going state-by-state. There is some folks in the industry that would love to see a separate category at the separate asset for energy storage. I don’t know that that is the most practical solution at this point, but it’s definitely a trend.

What I think most states—and I might be wrong about this—I’m sorry that this is going to be recorded because I don’t want to be forever saying this but, the preferred solution I think at this point is classifying energy storage for its primary purpose; that does not mean it cannot do all the other things. So, it’s definitely something that is out there and it does impact the participation, the compensation, business models, revenue models going forward. It’s actually a great question and I don’t think that it’s been solved. But it’s definitely not a 2030 question. It’s a 2020 question because those conversations are happening now.

Okay, great. Thank you. Andrew, can you discuss the range of thermal energy storage systems? It’s been coming up more and more as an option versus a couple of years ago. And we still have you on mute, Andrew. There we go.

Can you hear me?

There we go. Hi.

Hi. Sorry about that. Yeah, I saw that question come up and I wasn’t exactly sure what it referred to. By “range” it could mean range of costs, range of maturity levels, range of types. I would say kind of as an overarching statement that there is a wide range of thermal energy storage systems, both high temperature and some lower temperature. Some are designed for smaller scale applications; some are designed for very large-scale applications. Some, like the pumped heat varieties, are AC to AC and have their own power system. Some rely on cannibalizing an existing power island to produce power. So, some are commercial; molten salt has been applied commercially on concentrated solar, and some are very novel. And the costs kind of range all over the map. But in general, thermal energy storage tends to become cheaper than say batteries at durations longer than the six- to eight-hour range typically. So, I don’t know if that answered the question but I did the best I could there.

Okay, great. Thank you. This next one is for Larry, but all of our panelists can answer this one: What level of demonstration will utilities require for new technologies in order to accept them for grid interconnection, and how can DOE help get there?

Well, my case, of course, is a lot smaller. We have a lot of interaction with our RCA—our Regulatory Commission of Alaska. We have to do a lot of economic analysis, but ultimately, resiliency projects generally have an impact on economics that are unfavorable. So even for the project we did up here, there is a certain cost to it. But overall, it was something that our Board of Directors and our members were willing to take on to have a long-term view. Currently, it’s still a steep road to climb.

Okay, thank you. Eric, I’m going to give this one to you next. I’ve a number of questions about funding. So, for our Energy Storage Grand Challenge funding—is that available for commercial projects or is it just for R&D projects?

So, I will clarify that there is no specific funding for the Energy Storage Grand Challenge. What we’re doing initially is to put out a strategy for what the department could do over the next 10 years to accelerate energy storage technology, development, and leadership, and included within that strategy could be specific opportunities depending on the stage of the technology and the type of use. So, as you probably know, the DOE has a wide variety of funding mechanisms for every stage of development. So from basic material research such as fundamental R&D, to near commercialization assistance from the Office of Tech Transitions, or the debt type of assistance that the loan program office provides. So, this is a long way of saying there is nothing specific at this point. But what we hope to do is show how the existing mechanisms within DOE can help all stages of technology development.

Great, thank you. I’m going to toss this next one to Lola, but all of the panelists feel free to jump in here. What technologies do you all view as having the highest potential for very long-duration storage?

You are asking me about that one? I’m going to turn it back to you guys at DOE. You tell me what is the potential of the technology so far?

The question is ‘What are the potentials for long duration?”

Yeah. Which technologies have the highest potential for very long-duration storage?

Well, I mean, if you’re talking very long duration, you’re going to need to use a fuel. That’s the way energy storage is done today. And in the future, when you have lots of renewables and you need seasonal energy storage, you are going to need a fuel. And in that world, which will likely be a low carbon world, that fuel will in turn need to be a low carbon fuel, like a hydrogen or ammonia or some of the other low carbon fuels that have been discussed. So that’s the ultimate in energy storage, is doing fuel-based. Some of the others that I’ve talked about, like the thermal energy storage stuff, that cutoff around 24 to 48 hours is typical for the thoughts on what the duration hours will look like.

Okay. Thoughts from any of our other panelists?

I’ll throw something in there that maybe the audience might find interesting. But I think our paper kind of shows the need for storage and describes different buckets of need anticipated, but, you know—and this has been something that has been a challenge for many years—so our main energy storage platform for a long duration that’s dominant, right, is pumped hydro, and has a lot of challenges with building it, as folks know already. And it’s expensive, capital-intensive, but when you get to some of those scenarios, like 2045 zero carbon, then I think we are looking at quite a need there. So, the challenge for DOE and the group is how do we address those barriers and figure out a way to get some of that pumped hydro built?

Thank you for mentioning pumped hydro. I tend to always forget such an established technology, but it certainly has potential as well.

Very good. All right, Sandip, I’m going to give you this next question. A recent ERCOT inertia trending report noted that the inertia in ERCOT’s system is not declining any more while wind and solar is growing. Can you comment on the reason for that? Would the inertia continue to decline in the future?

Sure, if, you know, I’m referencing the same report that the questioner is referencing, then that report was an annual trend that we do on, you know, lowest minimum inertia that we observe in ERCOT, and what that report showed for 2019 was that in 2019 our lowest inertia wasn’t lower than previously observed lowest inertia in past few years. But that doesn’t change the trend of the inertia. Our inertia is, you know, overall if you look at the duration curve, it continues to decline. And, you know, in 2019 we didn’t make a new loaded card but overall the trend is still in the direction where we are adding more invertible resources and so we will continue to see that declining inertia trend.

Great. Thank you. Steve, you were mentioning in your presentation about the recent storms that have gone through the Southeast, so when using energy storage for electric supply and black start when hurricanes and tornadoes hit, how long is the duration of the energy source necessary for this purpose?

Yeah, I saw that question. I think it’s very dependent upon the system—you have two components. You have in a storage system both the power rating and the energy rating, so if you’re trying to black start, you need to think in terms of what is your power capacity, power rating, and then how long do you have that rating for? So, depending on what you’re trying to do, and depending upon your grid characteristics, it’s going to differ. There’s not a one answer for that. That’s just going to depend upon your circumstance and your grid.

Okay, thank you. Eric, a question for you back to the very beginning with your slides. There was an energy storage market potential of $6 billion to $20 billion, and how are those values developed?

So, we took—in some cases off-the-shelf and in some cases aggregated or extrapolated—the market projections that commercial market analysis companies, banks, and other sources have published. And that’s a U.S.-only stationary market annual capital expenditure estimate. So that’s a lot of disclaimers, but we were trying to just gauge what the industry might look like as a potential scenario. And we are interested to see if other people have other thoughts on what scenarios could exist for this industry in 2030 and beyond because that will really help us backfill an R&D strategy that will support this industry.

Thank you. Jordan, you talked about some use cases in your presentation. Will there be detailed information provided for each one? Information such as load, expected generation, etc.?

Yes. And so as part of the projects, we have communication plans, and so we intend to report out regularly at conferences. And so, you know, we’ll report out on results, and the use cases themselves, you know, we’ll have more definition added in line with the actual application. And, of course, for every time you would apply a concept like this, it would depend on the local system. So those system characteristics will be unique on a site-per-site basis. That won’t change the objective of the project or the validity of the results, but those characteristics will vary from site to site. But we’ll be publishing those results.

Very good. Thank you. Andrew, a question for you here. You very accurately described risk-averse buyers as being unwilling to buy serial number 1, or even 2 through 10 of a new technology. A large part of that reluctance is based on startup companies’ financial inability to offer performance guarantees and warranties. What role could federal validation or indemnification of new storage technologies play to help to assuage the concerns of risk-averse buyers?

Wow, that’s quite a question. I guess, not being a commercial guy, some comments on that. We’ve worked on demonstration projects where—you know, most of the risks that power plants want to avoid are financial related. So, if a larger scale demonstration is done on the site of an actual power plant, and after it’s done it actually can be owned and operated by the host, then that’s a good way to get serial number 1 out there. And then you have to make sure that for that project that the entire industry is able to be part of it so they can learn from the experiences of that nameplate number 1.

So, having significant dollars in place from federal resources to buy down some of the cost and risk of putting a first installation in place is really important. We have seen for energy storage that newer technologies are looking to take on a lot of risk by basically installing for free, and then making up the costs on like a PPA on the back end. So that’s a way for the owner to not take any risks. And for the developer, to make it up on the back end. So, that’s a way for the owner to not take any risk and for the developer to take most of the risk and make it up on the back end. That’s another way of doing it. But I think ultimately, just making sure that any of these federally funded projects are well attended by the power industry, and the testing of these facilities is very well documented and done in a real-world way is critical to getting buy-in for future customers.

Great. Thank you. Jordan, a question for you: What about repurposing EV batteries for stationary energy storage?

Yeah, actually sharp viewers may have caught that line in one of my slides. It is in there. The distributed charging resources project actually has a second life battery element in it. And so, what we’ll demonstrate there in some of those instances—that project will have several instances demonstrated in different places. And so several of those instances will utilize both a second life battery—now there are specific definitions for that term and we won’t get into that—but it will demonstrate a second life battery along with a primary battery and determine the effects of that, the implications, the costs, the performance, etc. Now there is a lot involved with second life batteries and that whole theory, as a lot of the attendees may be aware of, and one of them is ‘Can you provide the performance of the primary use battery at a constant level which makes it economically attractive?’

Thank you. This question is really for any of our panelists. Is there a specific parameter needed for the grid scale energy storage of price per kilowatt, power rate, etc.? Anyone want to take that?

I think it depends upon your particular application. So, I don’t think there is one cost target. For example I think as we move into deeper penetration of renewables, and that requires longer-duration storage, I think the price duration or the price target for longer-duration storage is different than short-duration storage. I think just like if you think about generated assets that are on the grid now, you have base load units and you have peakers and you have stuff that flexes in between. And each of those run at different kind of cost targets, depending upon their operating scenarios and the core technology behind them. I think the same is going to be true for storage. So, the stuff that operates quick and in a shorter duration typically can have a higher value, say like a peaker. The stuff that is a longer-duration bulk is going to have a lower price target because it’s kind of supplanting that bulk generation need, if you will. That’s my opinion.

All right, very good. Anyone else want to comment on that?

Yes, this is Jordan. Just real quick. We take sort of a performance-based approach, which is, you know, in many ways kind of like a black box approach. So, if you can meet all of our performance targets and all of our reliability requirements, then it is sort of a least cost, best fit application for storage.

Very good. All right. We are coming near the end here. So, Eric, I’ve got two last questions for you. One, there is a question about when folks can expect the draft roadmap to be released and when comments will be due on that. And then, part two, the second question here is from someone in the audience: My team and I are looking to use this challenge as part of a university senior design project. We would like to know if university students can participate in this challenge? So, Eric, I’ll turn it over to you.

Well first, I’m glad to hear we are reaching the next generation of scientists, engineers, and innovators. So even though the Energy Storage Grand Challenge isn’t a single event or opportunity, if this event has inspired your senior design team or anyone else on the line, I encourage you to share your ideas with that. You can do that formally through the upcoming RFI process, and I’ll talk about that in a second, or informally by contacting Vinod, myself, or other DOE staff on this team directly. This simply is going to help us formulate the roadmap to coordinate all the different parts of DOE to accelerate energy storage technologies. Yeah, so, before I hand it back, I just want to summarize something. The speakers you heard today provided really forward-looking examples for the emerging needs and opportunities for storage. You heard from everything from electric vehicles in California, to a remote Alaskan community, to neighborhoods in Alabama.

There are many uses for storage and lots of ways to provide those functionalities. And similarly, a lot of ways where DOE could potentially help through R&D. So, like today’s speakers, I’d encourage everyone to give us feedback on where DOE can best help this industry overcome technology pinch points or barriers. So, in addition to our upcoming virtual meetings, we are hoping to announce an RFI within the next couple of weeks, and in parallel with that, releasing the draft roadmap. And after that’s out, we’re hoping to have comments back from the public by late July, approximately. So, thank you again for joining this afternoon. Thank you to our speakers. And thanks to Lola for moderating. And then, back to you, Meredith.

Yeah. Thank you. So again, we are so excited to have so many people on the line today. If you have not already done so, we want to invite you to register for our three upcoming regional workshops. They’re going to be on May 19, May 20, and May 27. The link to register is on the screen but we will also include it to you all in a follow-up email. This concludes today’s workshop. We look forward to having you again later this month, and have a wonderful day. Thank you.