Annual Technology Baseline: The 2021 Electricity Update

Annual Technology Baseline: The 2021 Electricity Update

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>>Laura Vimmerstedt: Okay. I would like to go ahead and get started. Thank you all for joining the 2021 Annual Technology Baseline Update webinar. First, I'd like to acknowledge all of the collaborators who worked together to produce this update. Thank you to everyone from NREL and our partners at Oak Ridge and at DOE. Derek, did you want to explain the Q&A features of the webinar? >>Derek Barelski: Sure thing.

So we are in listen only mode for all attendees that are joining. To communicate with the presenters and the panelists, you can use the chat feature listed below. And if you see here in the picture here, you can click on these three dots and pop up the chat feature. You can feel free to use that and respond to everyone here. That way, everyone, all the attendees and all the panelists will see your questions and comments. If you have a question, feel free to use the Q&A feature, and that'll be specifically for questions and answers.

We will be recording this, and it'll be posted to the ATB website after the call. If you do have audio issues, feel free to dial in by phone. And if you have any other questions there, feel free to send me, the host, a chat.

And if you have any questions or concerns, feel free to reach out directly to me, the host, Derek Barelski. Thank you. >>Laura Vimmerstedt: Thanks, Derek. Okay. So as I mentioned, we're launching into the Annual Technology Baseline 2021 Update, and the leads for the technologies are listed on this slide.

So just a quick overview of the agenda. First, I'll talk a little bit about the motivation for the ATB, why we produced this product, and then I'll talk about the project and the overview of the ATB and how we do it. And then we'll launch into brief discussions from each of my colleagues about the technology-specific highlights that feature the new innovations that we are including in this year's projections. We'll touch briefly on the financial cases and methods that we used to produce the ATB, and then turn to your questions and comments.

So we produce the ATB each year to try to keep pace with rapid changes in technologies, to provide a consistent and unified set of data about the technology cost and performance characteristics across energy sectors. And we do this both for the Department of Energy's Energy Efficiency and Renewable Energy Division, for internal analyses at NREL as well as other DOE national laboratories, as well as to provide a resource for third party analysis. So the ATB assumptions are used in a wide variety of scenario analyses, some of which are shown here, and by many external parties, some of whom are shown here. The Annual Technology Baseline supports a companion report every year called the Standard Scenarios, and many times, questions that people have about scenarios for energy futures can be answered by referring to the Standard Scenarios Report.

The Annual Technology Baseline feeds into that report. So the ATB offers this suite of products shown here: a spreadsheet, website, interactive charts, and data in a variety of ways, formatted data and an API, which we've tried to build up this year. So those of you who can use an API, hopefully, those features will be helpful to you.

This PowerPoint, as well as the recording of this webinar, are also available via the website. And I wanted to note for everyone that next year, we are likely going to take on a significant change to the spreadsheet. So if you are interested in influencing the future course of the ATB spreadsheet, I really encourage you to register. If you become a registered user on the ATB, we will reach out to you to try to understand future directions for the spreadsheet.

So the ATB provides a lot of cost and performance data. These metrics are then used to calculate a levelized cost of energy as a summary metric for some technologies. The technologies that we have in ATB are shown here. New this year we have utility scale PV plus battery hybrids.

We have an enhanced representation of storage. And for the first time, we've collaborated with the National Energy Technology Laboratory to produce projections that take into account technology innovations for fossil and carbon capture and storage technologies. So you'll find that our natural gas and coal assumptions are all new based on NETL this year.

And that was curated by the US Department of Energy Fossil Energy Office. So as far as our methodology, we undertake three steps to produce the ATB assumptions. So essentially, we need to make binning decisions about technologies and resources. So we have resource bins and technology – representative technology categories for each technology.

We develop cost and performance assumptions based on technology innovations within those bins, and then we calculate the levelized cost of energy for some technologies. So the technologies/resource bins and technology categories are shown here for each of the technologies. And as an example, so this is the kind of binning that we do where the resource, in this example, for land-based wind, the resource is not equally high quality at each location. And so we bin locations, and you can see how the capacity factor at some locations is much better than others.

So our binning is attempting to represent diversity in the quality of the resource, as well as in some cases the type of technology. So in our second step, we develop the cost and performance data, and we use three different scenarios: a conservative, a moderate, and an advanced scenario. And these scenarios represent different levels of technology innovations.

So as you can see here, the conservative is aligned with today's levels of technology with little innovation. The moderate represents widespread adoption of things that are well within reach today. And the advanced represents a market success of a more unproven level of technology. Every year, we update the sources for our base year, and every year, we also update the technology innovations, although the general categories of technology innovation are fairly consistent from year to year. So in our third step, we use the cost, the capacity factor, the O&M, and the capital cost to calculate a levelized cost of energy. And as noted, the levelized cost of energy is a simplified and summary metric that's not necessarily good for all decisions, but we do include it for some technologies as a point of reference.

So across all of the technologies for this year's ATB, we have modified the assumptions for the financial cases that are used in calculating LCOE. We've brought the base year and dollar year forward to 2019, but – and moved historical data to – from 2019 to the historical category. But in general, our approach is broadly consistent with 2020. So some things to note in the website. On the ATB electricity data overview page, you can go in here and filter by technology, by parameter, by scenario, by cost recovery period. And I would encourage folks while we're on the line here today to just open up ATB and let us know if you are running into any challenges in figuring out the filters.

You can go to the download page, download slide decks, images, Tableau workbook, and you can run through each technology page and see examples, look at the data downloads and the about pages. And the about pages are a real rich source of detail on how we developed this resource. So now I'd like to turn to technology-specific highlights, so we're going to walk around the table of the folks who developed the data here in the ATB. And each analyst will provide a brief overview.

I would encourage you to pose questions in the Q&A as we're going around the table, as you hear questions, so that we can try to get those answered from the analysts. So turning to land-based wind, Tyler, would you like to take it away? >>Tyler Stehly: Sure. Yeah. Thanks, Laura.

Yeah, so may name is Tyler Stehly. I primarily led the land-based wind technology analysis with support of various colleagues within NREL. So my brief highlight is essentially updates to this year. The basis year, as Laura said, was updated to 2019, where our cap-ex and O&M estimates are based on utility-scale wind projects installed in the US in 2019, and is primarily informed by the data collection activities done in the Wind Energy Technology Data Update, 2020 edition, led by Lawrence Berkeley National Laboratory. This data is also published in NREL's 2019 Cost of Wind Energy Review. Within both those reports, additional detail on cost and performance and further cost breakdowns of wind turbine components can be found.

The net energy productions captured the average turbine characteristics installed in 2019. Examples of these characteristics would be the nameplate rating, rotor diameters, and hub heights found in the US for installed projects in 2019. And this is representative technologies placed at a representative one site that corresponds to a good wind resource, similar to what you would find in the wind belts of the United States. Some of the projections for each of the three scenarios assume different adoption levels of future technology innovations. So some of these innovations include blade segmentation, enabling larger rotors, modular towers, allowing higher hubs, and getting around the transportation constraints of the US infrastructure, and other advancements in wind turbine controls, advancing – reducing system loads and improving performance as well. The three scenarios for the future system cost and performance are defined and estimated by assuming a specific nameplate, rotor diameter, and hub heights in combination with bottom up cost modeling and performance tools.

The graphic you see in the slide here currently as representative is wind class four. This is kind of our – yeah, representative site within the US, typical of a good wind resource. Overall, the resource is split into ten different wind speed classes, and it's based on annual mean wind speed, which is consistent with those representative in the NREL ReEDS modeling. Additional details on this wind speed classification can be found on the ATB website, so encourage you to dig into that. The estimated cost reductions for cap-ex and O&M, in combination with the improvement in capacity factors, result in reducing LCOE by the three scenarios, with the greatest reductions being found in the advanced scenarios. Basically, in comparison with last year's ATB, we see similar trends for capacity factor improvements, O&M cost reductions.

However, this year, we integrated additional cap-ex reductions from increased adoption levels of advanced controls. This new assumption results in about a $3.00 per megawatt hour difference in 2030 from last year's ATB. So that's primarily the difference from last year's ATB, is this cap-ex – additional cap-ex reductions for future projections. And that's a brief summary from my end. Laura, shall we shift to offshore? >>Laura Vimmerstedt: Great.

Yes. Thank you, Tyler. I don't see any wind specific questions yet in the Q&A, but hopefully, the audience will ask you some soon. So Philipp, would you like to introduce us to offshore wind? >>Philipp Beiter: Great. Thank you, Laura. For offshore wind, I should start with a disclaimer to say that as of today and as of 2019, there has obviously been – there hasn't been any commercial scale offshore wind plant in the United States.

So the focus of our cost assessment and to validate our cost estimates for US plants is really more in sort of the early 2020s, 2022, 2023, when the first offshore wind plants are expected in the United States. Compared to last year's ATB, our assessment for the various cost components have actually not changed much for the baseline. You will see slight reductions in cap-ex and op-ex and a slight improvement in capacity factor as well for the 2019 baseline. We feel that our assessment from last year is still fair to characterize what we would consider a hypothetical cost for a 2019 commercial scale offshore wind plant.

And we've done some bottom up analysis with the announced projects, such as Vineyard Wind, for example, for the early 2020s, and feel that our assessment of cap-ex and op-ex is still relatively good _____ there. One methodological change that we implemented was that we shifted from – basically from an expert _____ approach to a learning curve approach for deriving projected costs. So for the cost between 2020 and 2050, we have been using an expert _____ that was published in 2018 to assess how costs and performance would develop over time in the past, and we're now using a learning curve approach where we're basically using empirical project data between 2014 and 2020 to basically develop an empirical relationship of where costs might go to in the future. So you'll see those reflected here in our projection numbers. For those, we're making assumptions around where – how much deployed capacity we would expect by 2030 and by 2050. You'll find the details of sort of the methodological – yeah, details in the description of the technology.

And another sort of major change was that for our reference class, we're using wind speed class three for fixed bottom, but we've shifted on the floating side from wind speed class 13 to 12. Wind speed class 12 represents a higher speed resource, and we feel that that is more representative of, for example, the call areas that are announced in California at the moment. In terms of technology parameters, we've held those constant compared to last year, so we're still assuming a six megawatt turbine in our baseline year of 2019. And through 2030, in the mid-scenario, we're assuming a 15 megawatt turbine for the moderate scenario and an 18 megawatt turbine for the – basically, the advanced scenario, and a 12 megawatt turbine for the conservative scenario.

That's all unchanged from last year. And yeah, I should – yeah, that's – I think that's all that I've got on offshore wind. >>Laura Vimmerstedt: Great. Thank you very much, Philipp. Next up, we have Dave Feldman to talk about photovoltaics.

And after that, we'll go to utility-scale photovoltaics plus battery store. Dave? Dave, it looks like you're still muted. >>David Feldman: I was double muted. Okay.

Sorry about that, Laura. >>Laura Vimmerstedt: Great. We can hear you now. >>David Feldman: Thanks for the opportunity.

Okay. Great. So yes, I'm David Feldman. I led – we have three different – three to four different parts of the PV. We do utility-scale, commercial and residential PV, and – which are standalone, and then we also have, as Laura mentioned, this year a utility-scale PV plus battery.

I led the PV standalone and supported the PV plus battery storage. The major changes that – there are sort of two buckets for all PV this year. The first is that as we do every year, most of our current and sort of 2019, 2020, 2021 numbers, are based off of our annual benchmark report that NREL produces, the US Solar Photovoltaic System and Energy Storage Cost Benchmark, so numbers for this report are based off our Q1 2020 report. And so all cap-ex was – for the current year was modified to include those updates. In that report, we also updated O&M, and that's a little bit different from what was done – what we did last year. We included a few categories that aren't typically thought of as what a lot of folks call O&M, but really go towards the – sort of the ongoing operating costs of the system, and those things can include planned lease costs, property taxes, things like that.

There's I think six different categories. And so while those aren't typical O&M, which was what we benchmarked, those really do represent more of the ongoing costs of PV systems, and therefore, since a lot of this data is used for LCOE or for electric cost analysis, we thought it was appropriate to include those cost categories. So that's one change from last year. The other significant change, in the previous ATBs, we – for capacity factor, we chose – we historically have chosen three or five representative locations around the US, like Kansas City or Phoenix and things like that. This year, to be more in line with other technologies, we binned – we made ten resource classes and binned the US by global – I'm sorry, global horizontal irradiance, so each – every part – everywhere in the US, there is – depending on sort of how sunny it is _____ on the performance. And we sort of binned the US into ten bins and ran our rev model for capacity factors across the US by county, and then we averaged those capacity factors based off of for utility scale, available land, and for commercial and residential, by population in each county.

So we also changed from this year to last year, previous years, we'd been using the benchmark report that I mentioned for the system losses calculated there, but in this year, we used system losses that are more consistent with default characteristics, and same in the _____. So _____ change that we made. We also, I guess lastly, last year, I think it was the first year that we started showing improvements in capacity factor over time, which was – we thought was important for a variety of things, research efforts underway to improve capacity factor, and certainly with the introduction of _____ modules that are becoming more and more popular in the US and globally, we thought it would be important to capture that. So this year, we made slight changes. I think we've – the improvements are not quite as dramatic as they were last year, and so you'll see these improvements not go up as much as they did last year, based off of new research and information that we've _____. Those are the big changes.

>>Laura Vimmerstedt: Great, David. Thank you so much. >>David Feldman: Yep. >>Laura Vimmerstedt: So next up, we have Caitlin Murphy to talk about one of our new technologies, utility-scale solar PV plus battery.

Caitlin? >>Caitlin Murphy: Yes. Thank you, Laura. Hello, everybody. My name is Caitlin Murphy, and I'm a senior energy analyst at NREL. I either lead or co-lead a lot of NREL's work in trying to understand the future value of hybrid systems, with a lot of our early work focusing on PV plus battery hybrids. So as Laura and Dave mentioned, this is the first year that the ATB includes a technology entry for the utility scale PV plus battery hybrid systems.

This addition was really made to reflect the growing industry interest in these technologies. So we're seeing in the Interconnection Queue data across the country that in some market regions this actually makes up the majority of proposed solar projects. So a decline in maybe standalone PV projects in certain regions, and instead being replaced by some of these hybrid systems that will combine utility-scale PV and battery technologies together in a variety of different configurations, some of which we don't always understand, based on the limited data that's provided in the Interconnection Queue data.

So a lot of what's included in our ATB entry is rooted in the same information that Dave just presented for utility-scale PV, and what you'll hear for utility-scale battery systems in a couple of minutes. So I won't spend my time here repeating what you're going to hear from them. Instead, I wanted to spend this time focusing on the most important decision we had to make in this addition, which was figuring out which configuration of utility-scale PV plus battery hybrids we wanted to include in the ATB for our first cut at this. So as I mentioned, the Interconnection Queue data is sometimes pretty limited in terms of what we can see for PV sizing, battery sizing, and the nature of couplings between those technologies in the hybrid systems.

So for this first cut, what we decided to do was take a pretty conservative approach and try to root our presentation in what it is we're seeing for the technologies and the systems that are online today and those that are being proposed with the most detail in the Interconnection Queue data. So what that turned out to be is a PV array that's pretty typical of your normal utility-scale PV projects without a battery. And then we coupled that with a battery component whose size is about half the capacity rating of a shared bidirectional inverter. So our default configuration is what we would typically refer to as a DC coupled system, and we've provided the costs and capacity factor information for that configuration in the spreadsheet, in the data that you would download.

But in our documentation, we also included some cost information for what the system would look like if we were to use separate inverters instead, because this nature of coupling I would say is one of the most uncertain features of hybrid systems in the near-term and also over the long-term. Also just note that we do expect that the industry will be pushing more and more towards oversizing the PV array. So this configuration doesn't necessarily do justice to all the synergies that can be captured by coupling utility-scale PV and batteries together. That's a direction we plan to head in future years. But for now, we really just wanted to get this out there and start populating our models with information about what a coupled system looks like and how that would change some of our grid evolution scenarios going forward in time.

In terms of the results, so what you're looking at on this slide here today, you'll see that both the capacity factor and the LCOE for the utility-scale PV plus battery systems, those are both a little bit higher than what you'll see for utility-scale PV. This is consistent with what we're seeing in our analyses, and it, importantly, doesn't reflect the non-energy services that the coupled battery can provide in these cases. So we're not capturing all of the benefits that a hybrid system could provide, both from the operator's perspective, but also the plant owner's perspective. In terms of the trajectory, so looking forward in time, you'll see that our trajectory looks a lot like the utility-scale PV one, and that's not a coincidence, since we're really rooted in that information.

We do see sort of rapid cost reductions over time, especially out to 2030, and then a more moderate reduction after that. So all of these trends are driven by the same information that Dave just presented in terms of how we achieve these cost reductions over time, and also the capacity factor improvements. You'll also see that the impacts of the markets and policy button on the left hand side here, those are all pretty similar to what you would see in utility-scale PV, because we do allow the battery component in this case to qualify for the ITC, so we're capturing that guidance from the IRS in the ability for a coupled battery to be able to qualify for the ITC benefits as well. That's everything I wanted to share today. Please don't hesitate to reach out, either in the Q&A or by email, if you have questions, since this is a new entry in the ATB. Thanks.

>>Laura Vimmerstedt: Thanks a lot, Caitlin. And I would encourage everyone to pose questions for Caitlin in the Q&A as soon as you think of them. I did also want to clarify one thing that Caitlin mentioned regarding the financial scenario shown here. So there are two sets of financial assumptions.

The market and policies set of financial assumptions does include the PTC and ITC. The R&D set is meant to just reflect innovation without those policy incentives of the ITC and PC. So next up we have Chad Augustine presenting about concentrating solar power. And Chad – oh, there, you should be off mute now. >>Chad Augustine: Okay.

Awesome. Thank you. Yes.

My name is Chad Augustine. I'm also a senior analyst at NREL. And I'm going to be talking about the concentrating solar power inputs for ATB 2021. I'd like to first thank Parthiv Kurup. He's the one who did the majority of the calculations on CSP.

I just get to present it for him. For concentrating solar power compared to 2020, there weren't too many updates. Obviously, we updated the basis year. Within the documentation, we also updated the classes so that they align with PV, with the same classes as PV, so that there are 12 of them, with class 1 being the best class. Another change for this year is that we were – we developed our current cost assumption within the system advisor model at NREL, also called SAM.

And so we have a SAM file that represents our reference case here in the ATB, so if you like, you can start with ATB and then make additional changes to it, to that scenario, within SAM, within the SAM model, if you like. Overall, for the three scenarios, the moderate scenario assumes some improvements within the CSP system. The base cases of what we call a gen 2 system, which has an upper temperature of 565 degrees Celsius using _____ nitrate salts and 14 hours of thermal energy storage. In the moderate case, we assume that that system upgrades to – from a steam turbine to a _____ turbine. That with some other changes, improving some heliostat costs, lower costs from currently, which are about [audio glitch] a watt [audio glitch] those costs [audio glitch] to about $4,600 per kilowatt.

Again, that's for 2030 in the moderate case. In the conservative case, we don't assume any changes or improvements, so the costs are constant. And for the advanced technology case, it mirrors DOE's gen 3 scenarios, which increases the receiver temperature to over 700 degrees Celsius, which improves the efficiency. It also switches over to the super critical _____ carbon dioxide power cycle, which also – which improves efficiency, and has lower heliostat costs as well. And – yeah, so that one, like I mentioned, tracks the gen 3 scenario or gen 3 plan from the Department of Energy.

And I think that's all I have for updates for CSP in 2021. >>Laura Vimmerstedt: Great. Thank you very much, Chad.

So next up, we have Greg Rhodes to present on geothermal. >>Greg Rhodes: Thank you, Laura. Hi, everyone. I'm Greg Rhodes. I'm a geothermal analyst here at NREL. As in previous years on the ATB we used DOE's Geothermal Electricity Technology Evaluation Model, or GETEM, to perform bottom up cost modeling for representative geothermal power plants.

We do that for flash, binary, and EGS, or enhanced geothermal systems. And in fact, the reason those are representative is because of the site-specific nature of geothermal resources. In terms of major updates, we updated the producer price indices from the Bureau of Labor Statistics as well as market, industry, and DOE, to evaluate recent research efforts and based on current – or recent Forge drilling _____ ongoing DOE project, we reduced drilling costs modestly, but those are slightly offset by increases in producer price indices. And that's why you'll see a fairly limited changed from last year's LCOE and cap-ex estimates.

We're – based on continuing research at the Forge project and improvements that industry has experienced, we expect to see greater decreases in cap-ex and O&M costs in the coming years. And for this year, we, again, were fairly in alignment with the DOE's 2019 Geovision Report, which sees significant cost improvements based on improvements in drilling rate, bit life, drilling bit life, and successful creation of advanced geothermal systems. So you see a major inflection point on the figures here in 2030, and it's assumed that we achieve most of those major innovations by 2030, and so we have an incremental and linear decline until that point, and then out to 2050 is a linear decline rate, linear learning curve, based on analysis done by the Energy Information Administration. And just one thing to highlight here is, again, you see a relatively high capacity factor. This figure – this geo _____ flash technologies _____ across the geothermal resource base, we use a fairly high capacity factor, and in fact, it might – we may increase that in the coming years, based on ongoing discussions. I think that's all I have, Laura.

>>Laura Vimmerstedt: Thanks so much, Greg. So next up, we have hydropower, and unfortunately, our lead hydro analyst from Oak Ridge National Laboratory, Debo Oladosu, was unable to join us for this webinar today, but we have Stuart Cohen from NREL who will present on hydropower instead, and then also present on pumped-storage hydro. Stuart? >>Stuart Cohen: Yeah. Thanks, Laura. So yeah, so as Laura said, I'm filling in, so I'm not the most familiar person with the hydropower changes that have been made for the ATB 2021.

But I would point that really, the main difference in 2021 is that there's some new – there's a new cost model that was developed at Oak Ridge for the non-power dam resource, and so particularly if you go onto the website, you can see that there's now a lot more detail there. And so the capital costs were assessed using a bottom up cost model for so far about 100 individual sites. It's going to be expanded to thousands of potential non-power dam sites across the United States. And so now the ATB contains detailed component costs and design characteristics associated with all these sites.

And then what shows up on the high level plot that you're seeing here is just an example of one of the characteristic sites that are being used to demonstrate the capital and the FOM cost improvements. The capital cost improvements for non-power dams were also updated with new information associated with expected increased use of advanced materials, such as composites and some of the structural components and turbines. But largely, a lot of the cost projection information also remains the same as previous years, where it was developed for the 2016 DOE Hydropower Vision.

And so that's really just a quick summary of the updates for the – on the hydropower side. And I guess if we go over to the pumped-storage slide, so this is my primary role, and this extremely boring slide is really just kind of a foreshadowing. What we're actually really excited about, which is we spent the last couple of years putting together a – the first ever comprehensive resource and cost assessment of closed-loop pumped-storage hydropower in the United States, and so that wasn't quite ready to be released along with everything else today, but within the next few months, we're looking at releasing that information, which is associated with a full topographic geospatial analysis of the US, including Alaska, Hawaiian Islands, and so that's going to be the most detailed resource characterization of closed-looped pumped hydropower that exists. And then we also included within that some cost modeling that's based on some work done at Australia National University on pumped-storage resource assessment and cost modeling.

And so that information will ultimately be added as an addendum to the ATB 2021, hopefully at the absolute latest by the end of this calendar year. And so what you're seeing here is just some initial data that we've put in to kind of get the webpage going and get pumped-storage into the spreadsheet to begin with, where we're just using some O&M cost numbers and also those round trip efficiencies that are based on the 2020 PNNL Energy Storage Grand Challenge Cost Assessment Report. And then, however, I will say that the forthcoming cost data is really just base year cost data, and the projections are still going to be based on the Hydropower Vision, so that would have to require additional work to understand updated future cost projections. But yeah, that is – that's all I have on the hydropower side. >>Laura Vimmerstedt: Great, Stuart. Thanks so much.

And thanks for bringing us this new technology this year. So next up, we're going to stick with the storage theme and bring Chad Augustine back to talk about batteries. >>Chad Augustine: Thanks, Laura. Yes.

Yeah. So for battery storage, we have three different scales, utility scale, commercial scale, and residential scale battery storage. They each have three separate pages on the ATB page. All of those projections come from – or I'm sorry, I should say are based off of the methodology we used in the Energy Storage Future Study, but the numbers haven't updated since then to 2021 numbers. Current costs, the current costs are based off of a bottom up cost model that's available in Feldman et al, 2021. So it looks at all the different components needed for a battery energy storage system and sizes and prices them correctly based off of the size of the system, its power, and the amount of energy storage – its energy storage capacity.

For future costs, we have – for the moderate case we have two sources. First, we use a literature review for total system cost projections for a four-hour system. We also have projections for battery pack costs from Bloomberg New Energy Finance through 2050. And because storage costs depend a lot on – sorry, battery energy storage system costs depend a lot on the cost of the battery packs, as duration increases, the amount of battery packs you need increases, and that will drive up costs.

And the battery packs are – they're projected to decrease in cost much more rapidly than the other components of the system, so we wanted to be able to account for that in future, that as you change the duration of the system, the cost – the battery – the – as duration increases, the cost for the entire system will decline faster, because the total costs are made up more by battery pack – by the battery pack, and those costs are declining faster than the other – the balance of system or the energy storage system. So by doing that, and then bringing it in future years over a range of storage durations and fitting a curve, we developed a correlation that accounts for both the cost of the battery packs itself and the rest of the components in the system and adjust accordingly, so that as you look at ten hour battery costs let's say in 2050, it does account for the fact that the battery pack prices are going to come down much faster and lower the longer duration costs faster. For the advanced and conservative scenarios, those are based solely off of our literature projections.

They do not include the battery pack, the specific battery pack cost projections for conservative and for an advanced scenario. It's only the moderate scenario that does that. And I think that's all I have. So it's back to you, Laura.

>>Laura Vimmerstedt: Great. Thanks so much, Chad. So next up, we're really excited to for the first time have fossil energy with CCS based on technology innovation research and development from DOE's Fossil Energy and from NETL. And Jeff Hoffmann is joining us to speak about this. Jeff, are you on the line? >>Jeff Hoffman: Yes, I am. Hopefully, we've ironed out the connection issues.

>>Laura Vimmerstedt: I can hear you. Thank you. >>Jeff Hoffman: Very good.

And thank you, Laura. As mentioned earlier, the 2021 ATB includes performance and cost estimates for coal and natural gas fueled electricity generating technologies provided by DOE's Office of Fossil Energy and Carbon Management. And you may note the addition of Carbon Management to our office name.

That is a recent change to better align with the current focus on carbon management technologies. FECM's inputs for 2021 were meant to align with the fossil fueled technology options that were previously represented in past ATB releases. Future participation is expected to include retrofit options for existing coal and natural gas fueled options, as well as data for systems equipped with CO2 capture greater than 90 percent and/or additional partial capture rates. Estimates of cost and performance for currently available fossil fuel electricity generating technologies are representative of current commercial offerings and/or projects that began commercial service within the past ten years. Coal fueled options include pulverized coal plants with and without carbon capture, including midlevel capture, approximately 36 percent reduction, and high level capture, approximately 90 percent reduction.

A coal fueled option without carbon capture is also included that provides insights into the cost and performance impacts associated with the inclusion of carbon capture technology. The cost and performance estimates are based on bottoms up techno-economic analyses that are well-documented in FECM's Cost and Performance Baseline Report published by the National Energy Technology Laboratory. I will note that the cost included in the NETL Cost and Performance Baseline are in 2018 dollars, and the costs represented here are slightly adjusted to 2019 dollars, to make sure that they are consistent with the ATB cost basis. Estimates of performance and cost for future fossil fueled electricity generating technology options are meant to capture incremental cost reductions that occur over time, i.e., learning

by doing improvements that are most often the result of more process design optimization and/or reduced costs that are due to improvements in equipment manufacturing practices, as well as deployment of advanced technologies that result from fossil energy research and development. The conservative scenario represents incremental improvements in capital costs without any improvements through FE R&D, and the advanced reflects achieving the FD R&D technology goals as captured in the 2020 Fossil Energy Roadmap. It is important to recognize that the estimates of future fossil technology costs and performance for the advanced scenario are based on representative technology pathways and should not be interpreted as representing the only technology pathways that enable meeting FE R&D goals.

For the 2021 ATB, the coal pathway begins with state of the art super critical pulverized coal plants or capture including post-combustion capture, carbon capture, and includes improvements to the base combustion plant, deployment of high efficiency advanced ultra super critical PC technology, as well as improvements to post-combustion capture technology. The coal pathway in the advanced scenarios does not include improvements to the pre-combustion pathway, or integrated gassification combined cycle, and no improvements other than learning by doing are included in the IGTC pathway in the 2021 ATB. The natural gas pathway represents state of the art F class technology for both simple cycle and combined cycle configurations, and includes early improvements to post-combustion carbon capture technology for natural gas combined cycle applications, and subsequent deployment of advanced natural gas fuel systems equipped with carbon capture. Other notable changes for ATB 2021 are the inclusion of property taxes and insurance as an element of fixed operating costs. These cost elements were not included in past ATBs, and their inclusion now provides a more consistent representation of costs compared to the renewable technologies. You're also likely to notice that as published, ATB 2021 does not include LCOE for fossil technologies.

LCOE is heavily impacted by a wide range of user assumptions, and prior releases of the ATB relied on a set of assumptions that were at times substantively different than assumptions in other parts of the department, such as fossil energy. The 2021 ATB provides sufficient information for a user to input their own assumptions for inputs, such as fuel cost and capacity factor, and develop their own estimates of the cost of electricity generation from fossil fueled electricity generating technologies. I'll close with that.

>>Laura Vimmerstedt: Thanks so much, Jeff. And we have one more technology to discuss, but while we're doing that, I hope that everyone thinks about questions that you'd like to pose during our Q&A. We have a great start, and we're looking forward to answering your questions, but would welcome others. So please submit your questions, and for the final technology, Wesley Cole will be presenting. Wesley? >>Wesley Cole: Hey, Laura.

Thanks. So for biopower and nuclear, these are pretty straightforward. If you're familiar from prior years, we used – we pulled several technologies from the Energy Information Administration's Annual Energy Outlook projections. We used to pull a lot of fossil technologies from there. You just saw Jeff talk about what we're using now in place of that. But we still have two technologies left that are kind of these outliers, _____ technologies, biopower, nuclear, where we're just digesting these effectively from the Annual Energy Outlook 2021 projections.

So the assumptions are all the same assumptions that are used by EIA in developing these projections. You can see how the LCOE and cap-ex and O&M are projected out over time. The biopower is a dedicated biopower plant, so it's solid biopower plants. The nuclear plant is an AT1000 brownfield site, so this isn't a small modular reactor that you hear talked about.

So that's – it's a pretty simple summary. I'm just going to leave it short and sweet like that. Happy to follow up if you have other questions there. >>Laura Vimmerstedt: Thanks so much, Wesley. So now for our – sorry, I'm going to jump to Q&A for a moment before we go into financial cases, because we are losing Caitlin at the top of the hour. Caitlin, did you want to address any of the questions that are coming in for you on the utility-scale battery plus PV storage? >>Caitlin Murphy: Thanks, Laura.

I think I was able to write responses to folks, but please do let me know if I've either missed the spirit of your question or if my answer drove new questions. The one question maybe I'll address verbally here is Kent's questions about capacity credits and the system value that can be achieved through hybridization. I definitely agree, Kent, that capacity credit is a very localized value, and certainly, you could have separate PV and battery systems where the joint capacity credit would be higher than in the hybrid system. But we are seeing that depending on sort of what the system configuration looks like and the transmission congestion might be, hybrids certainly offer capacity credit benefits for the PV components.

I don't think we have any questions about that, and I don't think that was your question, either. And potentially, they can lead to beneficial features for the system, if they're able to mitigate some transmission congestion features locally. But again, these aren't universal things, just potential benefits of hybridization, depending on where they're located and how they're designed.

>>Laura Vimmerstedt: Great. Thank you, Caitlin. So next, we're going to be discussing the financial cases and methods that we use, and Dave Feldman will be presenting that.

So as I mentioned before, we do have these two different sets of financial assumptions. We have the R&D case, and we have the markets and policy case that takes into account the ITC and PTC. So Dave, it looks like you're still muted.

So if you – there you go. >>David Feldman: Yes. On purpose. So yeah, thanks, Laura. So our financial assumptions for this year's ATB are similar and pretty much identical in methodology from last year's, which were based off of – last year, as part of the ATB, we did a separate set of work and put together a technical report called Current and Future Costs of Renewable Energy Project Finance Across Technologies. So as part of that work, we benchmarked financial costs for a variety of renewable energy technologies as well as natural gas.

For this year's report, the big update is that between last year and this year, Congress passed – I guess it's two updates. But the big update is Congress passed extensions to some tax credits, and then sort of added a new tax credit for offshore wind. And so because those tax credits changed, financing is set up to optimize – well to optimize those types of credits.

So oftentimes, while tax credits are obviously beneficial, they mean that projects have to adjust how much debt they can put on a project, so that changes the capital structure. So because of the increased tax credits, we had to change the _____ percentages between last year and this year because of those extensions. The other change, as we've talked about, we've been working together with NTEL on non-renewable technology benchmarking, and so we worked together with them to slightly adjust some of the assumptions we had on those technologies to more conform with some of their assumptions. But as you can – that was the second. But as you can see on this graphic, going back to the first big change, this shows – to the left, you can see the debt fraction changes over time, and you can see all of them going up over time as these tax credits slowly phase out, as they're scheduled to under law, or in some cases [audio glitch]. And you can see on the right hand side with the R&D case that there's no – there's no tax credits, so there's no need to change.

I guess the other thing to mention is the R&D financing case represents a WAC or cost of financing that is really not seen in the marketplace for renewables, and that's – so in some ways, it's artificially low, but it's not that it's artificially low, it's that we live in a world with tax credits, and so what we're _____ is a world without tax credits, and that's _____. That's all I'll say about that, unless there are any questions. Thanks. >>Laura Vimmerstedt: Okay. Thanks, Dave.

So I just wanted to remind everyone before we go to Q&A to please register as an ATB user, and that will enable us to let you know when things change in the ATB, when it comes out, and when the webinar occurs. So please do register as an ATB user. You will not be automatically registered just because of your attendance today. So we encourage you to do that. And I'd like to acknowledge DOE as the sponsor of this.

And as we roll into Q&A, I'm now displaying the instructions, so if you have any technical difficulties with the Q&A so far, please refer to these instructions. So my colleague Brian Mirletz, who has been deeply involved with the production of the ATB, is going to join here and help kick off the Q&A. Brian, did you want to start us into the Q&A? >>Brian Mirletz: Sure. I guess the question that I'll start with paraphrasing is why might someone choose to use the ATB data as opposed to EIA or some other source. >>Laura Vimmerstedt: And is that a question to me? >>Brian Mirletz: Yes. >>Laura Vimmerstedt: Okay.

So the big focus that we have within the ATB is on technology innovation, and so because we are based in the DOE's Energy Efficiency Renewable Energy Research and Development and Fossil Energy and Carbon Management Research and Development, our network of national laboratory and DOE program managers is aware – very aware of the R&D that we are doing and the technology innovation that we expect and anticipate in the coming years from that effort. And so the ATB is really intended to reflect what technology innovations we anticipate from that R&D perspective. Certainly, there are many other sources of data and projections, but we think that our perspective on the technology innovation side is a unique contribution to that set of different options. >>Brian Mirletz: Great.

Thank you. For the next question, we already got a great answer from Tyler in the chat for land-based wind, but the question was about multiple technologies, so I'd like to get an answer from both David for PV and Philipp for offshore wind. So for wind, offshore wind, solar, etcetera, can you us specific locations and nameplate quantities of the various class resources? For example, how many gigawatts of class one onshore wind resources exist? Obviously, replace with your respective technology.

And where are those resources physically located? So I guess, David, if you could go first. >>David Feldman: Sure. I mean, the US PV is located all across the US. So they're in each resource class.

I don't have – let's see. Let me see if I have the data out. I can tell you the average resource class historically has been I believe a five.

But it really depends on the sector. So – yeah, I don't – I mean, yeah, so the overall average of the resource class is about a five, for non-residential or commercial PV, more like a seven. Yeah.

It's pretty – there's no – PV has the benefit of being located in – being economic in a lot of different resource areas, depending on other factors. I guess maybe a better way to answer the question is I don't have – we don't have data of each individual PV site across the US by GHI location, but we have some granular data, and we certainly know the average resource classes by – resource by state. And so they're pretty much everywhere.

I'm not sure if that's a good answer to that question, but that's all we – >>Laura Vimmerstedt: You know, Dave, I would also just like to clarify that the ATB does not have detailed geospatial resource data, but there is very detailed gridded geospatial resource data available for wind and PV, wind and solar, from NREL. And so I think when – if folks come to ATB with questions that are really kind of resource geospatial data questions, I usually refer them to those data sets. So ATB sort of necessarily, because it is a summary product, is binning resource.

But if someone wants to drill down into very granular data, those data sets are available. >>Philipp Beiter: Thanks, Laura. This is Philipp. And yeah, what I'll add here, this is probably a good description for the _____ of the offshore wind resource as well. So for the ATB, we do rely on a resource assessment that goes basically from shoreline out to the EZ, kind of exclusive zone. Take into account spatial exclusions, competing uses, and assess the ATB cost for more than 7,000 sites for the continental US and Hawaii, and that spatial assessment allows us to take into account variation in wind speeds and water depth, distance to shore, distance to ports.

And then that entire resource of around 2,000 gigawatts is being divided up into wind – these 14 wind speed classes. And you'll find sort of a detailed breakdown in terms of the proportions that are assigned to each wind speed class in – as part of the ATB documentation for offshore. So I _____ there for some of the detailed breakdown as to the capacity that's associated with each wind speed class.

And lastly, just wanted to mention that for offshore wind, we're assuming a wind plant size of 1,000 megawatts. Thanks a lot. >>Brian Mirletz: Great. Thank you. I think at this point, the analysts have done a great job of answering all of the questions in the chat. I don't know if anyone has one that they want – that they thought was particularly interesting to highlight verbally, or if any of the other participants have questions that they would like to drop into the chat at this time.

>>Laura Vimmerstedt: Yeah, and while folks are thinking about that, I would like to jump over to a little bit more of a demo of the site. Are folks – Brian, can you see the website on my screen? >>Brian Mirletz: I can. >>Laura Vimmerstedt: Okay. Great.

So I am on the initial data overview page, and I just wanted to highlight – there were some questions about the Tableau chart functionality. So every chart – almost every chart on the site is built in Tableau, and this button, this – in the lower right hand corner, this rectangle with an arrow pointing downward is the download button. So if you click on that, you can download any chart that's on the site.

In addition, when you go to the data area, that's where you can download kind of the summary CSV files or the Tableau workbooks with almost every chart that's in the site. So there's a lot in here. In these overview – sorry, I'm jumping around here. Okay, so in each of the sites for each of the technologies, you'll see the chart that comes up in just a little minute, where you can select the filters that I was talking about. Here it comes.

So you can select by scenario on the overview page. You can select by technology. And – there we go. So parameters, so now it's showing LCOE and cap-ex, but you can select among the parameters. We have the two different financial scenarios, the cost recovery period, and these charts do display a single default technology and resource category, but as you can see here, you can choose which one to pick.

So that's just a brief tour here. Again, encourage folks to look at the about section for lots of details. Brian, I guess back to you. Other questions that folks would like to highlight here in our discussion? >>Brian Mirletz: Here we go. I think we've got one for Jeff here.

Given that carbon capture and storage costs are a function of multiple components, capture costs, transport costs, and storage costs, does NREL or _____ DOE FE have any assumptions around these detailed components? Do we also make any assumptions around future carbon storage hubs? >>Jeff Hoffman: So in response to the first question, yes, there is detailed information in the mentioned Cost and Performance Baseline Study, which is available on NETL's website. I believe there are also links to that in the reference section of the ATB documentation. In terms of the second question regarding storage hubs, that is a work in progress, and in terms of assumptions, yes, there are characteristic assumptions for different formations, and much of that is also detailed on NETL's website. In particular, there are two spreadsheet tools, a storage cost model and a transport cost model.

And each goes into regionally specific levels of detail. >>Brian Mirletz: Great. Thank you. At this point, we're out of questions, if anyone – we can probably wait another minute or two, if anyone wants to post – oh, here we go.

So is – ah, yes. So this one's for Chad. Is residential storage assumed to be in a conditioned space? >>Chad Augustine: Oh, okay. I understand. As opposed to being external, like – >>Brian Mirletz: Correct. >>Chad Augustine: I don't think we went into that level of detail.

I honestly can't say whether we assume that is a conditioned space or not. I don't believe so. I'd have to look deeper into the model. I don't think that's an assumption that we make one way or the other. >>Laura Vimmerstedt: So it might come up as like a temperature that you – like the battery performance would change at different temperatures, and so if there's – probably there's an implicit assumption of temperature in the performance, but it may not be clearly distinguished.

>>Chad Augustine: Yeah, that would be my assumption. I can go into the bottom up model and see if there's any indication of whether it's a conditioned space or not, but the short answer is I'm not sure. >>Brian Mirletz: All right. Thank you. >>Laura Vimmerstedt: So Brian, there was one other question I think for me about whether we captured recent commodity inflation effects in the ATB.

And so the very recent 2020 to 2021 effects, definitely not, and that's a great question. So thank you for that. And I guess, Brian, if there are other questions that were answered already in the chat that folks might like to elaborate on, we can do that as well. >>Brian Mirletz: Yeah.

One more just came in for you, I think. Are there plans to incorporate hydrogen in future analysis? >>Laura Vimmerstedt: Yeah. Great question.

So every year, we kind of assess what to include and what not to include. That is definitely an interesting area. So I hope everyone's aware that last year for the first time we launched a companion site, the Transportation ATB site, and that site does already include hydrogen with a target to the transportation market. So what we have not yet done is to think about hydrogen in the electricity market.

Wesley, you'd be welcome to comment more on this. But essentially, when and if we do that, we would want to have consistency between the transportation ATB and the electricity side of things, and have the electricity side deal with the distinctions for electricity, like what kind of device would be using the hydrogen. On the transportation side of things, you can see, if you jump over there, that we have quite a number of different pathways, everything from steam methane reforming to renewable hydrogen via electrolysis and using renewable electricity generation. So that's kind of our status on hydrogen. Thanks for that question.

>>Brian Mirletz: Thank you. And yeah, I'm not seeing any questions that we haven't answered at this point. >>Laura Vimmerstedt: Okay. Brian, are there any questions that you thought were particularly interesting to highlight for the whole group? >>Brian Mirletz: Sure. I think there was a question about changes in fixed O&M costs for this year's ATB versus last year's ATB, and this one was for Dave. >>Laura Vimmerstedt: Dave, it looks like you're still muted.

>>David Feldman: Sorry. Double muted again. Thanks. I think, as I mentioned in the talk briefly, you know, between this year and last year, there's a bunch of costs that are not considered traditional O&M, and so when people talk about O&M, they don't typically think of these costs, and they might be included in a more detailed model.

But because a lot of these numbers get used solely without _____ detail, we thought it would be appropriate to include those things in this year's modeling efforts. So the five additional categories that we include are land lease costs, property taxes, insurance, asset management, and security. And we get that information from reports that LBNL put out in 2020, where they did a survey of a bunch of – from the leading asset managers for PV and wind. So we're hoping to get more detail on that in the coming years, as far as how those numbers vary across the US. And certainly, there's a lot of interest in changing insurance costs for PV and wind recently in light of natural disasters, hail and tornados, hurricanes and things like that.

I hope that's helpful. >>Brian Mirletz: Yes. Thank you.

>>Laura Vimmerstedt: Okay. Any other questions? >>Brian Mirletz: Like I said, I think the analysts did a great job of answering things via text during the presentation, so I think unless anyone has a last minute question they'd like to pose, I think we might be all set. >>Laura Vimmerstedt: All right.

Well, I see 41 attendees who are still there who must be wondering something. So I'll hold the line for another minute. And if any of the questions that we posed – if you need more information, please don't hesitate to reach out to us. And please do register as an ATB user, and we'd be happy to try answer anything that you might think of later as well.

So unless there's anything else, going once, going twice, I'd like to thank all of our panelists very much, and thanks to all the attendees, and please enjoy the ATB.

2021-07-27 14:22

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