Hello, everyone. Okay, so we just started the recording, so I'll restart that. Hello, everyone, and thank you for joining the webinar. My name is Mark Bollinger, and I'm a research scientist at the Lawrence Berkeley National Laboratory.
I'm joined today by my colleague, Joachim Seale, also known as Yo for short. And together, Yo and I will be walking you through highlights from the 2023 edition of our annual Utility Scale Solar Report. We are recording the webinar and we'll post the recording to our website shortly after the event, and all registrants will get an email that contains a link to the recording and the slides. If you do have any questions while we're presenting, please type them into Zoom's Q&A feature and we will do our best to answer as many of those as we can, either during or after the webinar. And then finally, I want to thank the U.S.
Department of Energy's Solar Energy Technologies Office for funding this work. So next slide please. Okay so this is the 11th year that we've published this report and as in past years the purpose is to compile and analyze a wide array of publicly available data to reveal key trends in the U.S. utility scale solar market.
We define utility scale solar to include any ground-mounted project that's larger than five megawatts of AC capacity. So if you're interested in smaller ground-mounted projects or perhaps rooftop projects, I would encourage you to look at Berkeley Lab's companion report called Tracking the Sun, which covers a lot of information about those smaller projects. And you can find that at trackingthesun.lbl.gov. In addition to this webinar, other products that are included with this release include a PowerPoint-style report. which closely resembles the slide deck that you'll see today.
We also put out an Excel data file that contains all of the data behind the graphics that you find in the report. There's also a written executive summary and also online interactive data visualizations. And you can find all of that at utilitiescalesolar.lbl.gov. Next slide.
Okay, so here you see the chapter headings for the report. And we are going to basically touch on content from pretty much every single chapter of the report today, with the exception of those two that I've lightened out here and crossed out. So specifically, we will not cover any content on concentrating solar thermal power or CSP plants just due to the relative inactivity in that segment of the market over the past five to 10 years.
In addition, we won't run through our data and methods. If anyone's curious about that, I would encourage you to take a look at the full report. But we will be touching on all of the other elements that you see listed here.
Next slide. Whoops. Was there one in there on the regionals or did you take that one out?
Yeah. I'm sorry. I took that out.
Okay. Yeah. All right.
Well, with that, let me pass it over to Yo to actually jump into the content. Okay. Thank you, Mark. And a warm welcome from me as well.
In the first section. I will now present some of the overarching deployment and technology trends to provide you with some background and for the for the later discussion. But before diving into the details, I wanted to start out with a high level introduction. And here we can see a graph from the solar energy industry association and what Mackenzie and they asked me that in the last year in 2022, about 20 gigawatts DC of solar was installed. It's a little bit less than in the prior year due to a weaker showing of the utility-scale solar sector, which traditionally has been the driver of solar growth in the United States.
We will disentangle some of the reasons why large-scale solar contracted by about 30% or so last year. But for the moment, I just wanted to emphasize that looking forward, the industry experts expect a return to strong growth. with an annual deployment ramping up to nearly 40 gigawatts a year in the next two years.
Despite some of these deployment challenges, solar again is the leading source of new generation capacity in the United States in the year 2022. Out of all the added capacity, solar made up a record of 49 percent. However, our analysis only focuses on a sub-sample of all the solar. namely and for the past year 2022 we have a sample of 147 new projects that were completed in the chief's commercial operation in that year they account for 13.2 gigawatts dc or 10.4 gigawatts ac On this slide, you can see the monthly cumulative capacity additions over the course of a year and how individual years compare to one another.
The year 2022 is the black solid line, while past years are shown in the blue dashes. You can see that up until July 2022, build-out was pretty much on par with the previous year 2021, but then capacity additions seemed to stall. And a couple of factors may have contributed to this. For example, Increased anti-dumping circumvention investigations against four Southeast Asian countries began in the late spring, and multiple gigawatts of modules were seized at ports after the Uyghur Forced Labor Prevention Act became effective in July of 2022. The EIA reported that a growing number of projects experienced delays up to 20% of all the plans.
Towards the end of 2022, more capacity managed to come online, however, which seems to indicate that it was not just a strategic withholding of new capacity to then benefit from the more lucrative IRA benefits that started in the year 2023. Looking ahead, 2023 seems to be a record year, as EIA estimates more than 24 gigawatts AC of solar to come online, kicking off a new boom period for utility scale solar. So for the next year, then even for 2024, they estimate up to 35 gigawatts AC of projects larger than 50 miles. This 5 megawatts AC.
But not all of the solar is uniformly spread across the United States. Here you can see deployment by region. You can see that Texas has really established itself as a solar hotbed, having added the most capacity of all the regions that we analyzed in the past year, about two and a half gigawatts AC or a quarter of all the new utility scale solar capacity. And after a few sluggish years, California bounced back last year and added more than two gigawatts in 2022, the most that it has ever installed since 2016. And that's Southeast. Florida, Virginia, and Georgia continue to lead solar growth there, though at slightly lower levels than in the prior year.
As a percentage of in-state generation, California has the most solar market share of 27% in the year 2022, while Nevada, Massachusetts, Vermont, and Hawaii have all surpassed 17% and some of them even 20%. Thank you for listening. Despite the large capacity additions that I've already mentioned for Texas, Texas solar only makes up for 5% of all generated electricity so far.
And on a national level, solar still has some headroom to grow into as overall penetration only is 4.7%. You can explore these and many other statistics and trends yourself in interactive data visualizations that are on our project website. So here is a map that shows the seven ISO regions and then two additional broad regions, the West non-ISO territory and the Southeast non-ISO territory. You can see all the utility scale polar additions in the US and with those of 2022 highlighted in a dark blue color.
You can see that utility scale PV is not really well represented throughout the nation with the exception of upper Midwest states and the wind belt. So that's Montana and the Dakota. Interestingly, in Texas, all of the new solar capacity that was built was built outside of the western panhandle, where really most of the prior solar build-out has taken place in previous years. 2022 also had record solar hybrid deployment, where solar was... coupled with storage.
We will talk about that a little bit later in the discussion, but it's best to say that we have 35 new projects here and that California is really the leader in that particular segment. Again, we have interactive visualizations on our website where you can dive deep into project-level technical characteristics if you are interested in. The Inflation Reduction Act offers tax credits of 10% for solar projects that are located in energy communities.
and that incentive started to in the year 2023. No such credits were available in prior years, and it seems somewhat unlikely that for the new 2023 project that these were already intentionally cited. in these communities given just the long development timeline that these projects have and they're rather late notice what actually makes up such a community. But if we just look at the new deployment over the past seven months, it looks at a little bit more than half of all the new capacity in 2023 may be eligible for the energy community tax credit adder. So that may benefit these projects quite a bit and hopefully the local communities there as well. Single axis tracking has really dominated solar additions over the past eight years or so.
But this was especially true in 2022, where now nine and a half out of ten modules were mounted on trackers that follow the sun over the course of the day, which then results in a higher annual output compared to a fixed tilt system. These fixed tilt projects are really only being built now in particularly challenging sites. for example, where the terrain is particularly difficult or wind loading is very high, or in the very least sunny regions in the northeast. Many other high-latitude states, such as Oregon, Minnesota, Michigan, or Wisconsin, even those predominantly added trackers in 2022. The cost premium for trackers, which I'll touch upon a little bit more in a moment, is now 17 cents.
of watts and because of that overall economics are really in favor of adding trackers in most of the US. We measure the strength of the solar resource in kilowatt hours per square meter per day that's a metric known as the global horizontal irradiance or GHI and if we look at the median GHI across all projects we can see that the early installations happen in the southwest with a lot of sunshine, but that then GHI declined as the solar market expanded to the rest of the country. The year 2022 had the second lowest average solar resource of new installations.
It was just above four and a half kilowatt hours per square meter a day. And that again shows now the impact of the new northern installations that we have. Um, All else equal, the build-out of lower GHI types will dampen the average performance across all the systems that Mark will discuss a little later.
As module prices have come down over the past years, we've seen a flow trend to increase the module array DC capacity relative to the inverter AC capacity. And the ratio of the two is what we call the inverter loading ratio, or short ILR. And then higher ILR can increase the utilization factor of the inverter and reduce output variability at a project. In 2022, the DC capacity was on average 40% greater than the inverter capacity for fixed-tool projects. For tracking projects, it was a little less, and it actually decreased a little bit from prior years.
The DC module array was about 30% larger than the AC capacity. Again, all of equal, this trend of increasing the DC side will boost average project performance, as we will discuss later. And that is also the reason why we sometimes distinguish here between statistics in our presentation that are either denominated in Watt DC or Watt AC.
I will now share with you some of our new research findings of upfront capital costs of utility-scale solar. To compare apples with apples, we're excluding any potential battery cost adders among hybrid projects from our next few statistics. Because of time limits, I will not discuss operation and maintenance costs, but you can find that information drawn from a now very rich sample in the original briefing deck and then the data sheets that we've posted online. It's not easy getting reliable cost information.
We rely on confidential developer interviews, public regulatory filings, and press statements, and have gathered cost information for 59 projects that came online last year, representing a little bit less than half of all the new capacity that was built in 2022. For earlier years, we were collaborating with the EIA to get confidential cost information for nearly all the projects that were built up until the year 2021. We just cost to account for general inflation, something particularly important for last year, and report all of our costs in real 2022 dollars. And although we've heard from others about substantial component cost increases in 2022, rising costs do not really materialize in our sample. of projects that achieved commercial operations in 2022. And that is true neither in nominal nor in real dollar terms. Instead, we found continued cost decline from about $1.50 in 2021 to now $1.30 per watt AC in 2022. The cheapest 20% of all projects cost about $1.10.
or 80 cents per watt DC in the year 2022. Again, this sample is only backward looking for projects that came online last year and do not reflect the cost of new projects that are built in 2023. On this slide, we will now focus only on the 2022 installations and examine how project costs vary with project size and we can see that even in the utility scale sector, they appear to be economies of scale. Projects ranging between 20 and 300 megawatts are now 40 cents per watt cheaper or 26% cheaper than projects that are smaller and range in size between 5 and 20 megawatts or so. If we denominate the cost in Watt DC, the largest projects have even greater economies of scale and come in now at just 82 cents a watt. In our workbook, we have, again, more detailed cost estimates, such as cost variations by state or broader region, but I won't be able to dive into those today in the interest of time.
And I'll now hand it back to Mark, who will discuss how these projects actually perform. All right, thank you, Yo. So we do track the performance of the utility-scale PV fleet using primarily the metric of capacity factor.
And for those of you not familiar with the term, Capacity factor simply refers to the amount of electricity that a plant generates over a given time period relative to the amount of electricity the plant could have generated if it were operating at full capacity around the clock over that same time period. So it's expressed, it's a ratio expressed as a percentage. And if we go to the next slide, yo, among the full utility scale PV fleet. that we track, which in this case includes about a thousand plants totaling 50 gigawatts.
The median capacity factor is 24%, and that is expressed in AC terms, not DC terms. But if you look at this graph, and particularly the circles on the graph, each of which represents an individual plant, you can see that there's a wide variation in plant level capacity factor, ranging from a low of just 9% way over on the left, to a high of around 35% over on the right. And this graph breaks out or categorizes projects into 32 different bins based on the three primary drivers of capacity factor, which are the strength of the solar resource at each site, which we measure in terms of the long-term average global horizontal irradiance at each site location. And what you see here is that if you move from the lowest quartile, GHI, over on the left to the highest quartile, on average, you're going to increase your capacity factor by about eight percentage points, all else being equal. The second driver is how the array is mounted, whether it's at a fixed tilt or uses single-axis tracking.
And in this case, tracking can boost your average capacity factor by about four percentage points. And then the final breakout we show here is with the DC to AC ratio that Yo mentioned, also known as inverter loading ratio. And again, we break it down into quartiles here and find that the average difference between the lowest and highest quartile amounts to around three percentage points.
So if we go to the next slide, we can also look at capacity factors regionally. And Perhaps not surprisingly, we find the highest capacity factors in California and the West, which we often think of as the sunniest parts of the country, particularly the Southwest. And the lowest capacity factors are in the Northeast, in New York and New England. You can also see on this graph, if you compare the red and blue columns, that single-axis tracking tends to provide a greater boost in those high-insulation regions like California and the West than it does in...
the low insulation regions like the northeast and most likely as a result we tend to see a much higher proportion of tracking projects in those sunnier regions than we do in the less sunny areas. Next slide. So the last two slides looked at cumulative capacity factors, but it's also interesting to look at how capacity factors vary by plant vintage.
So on this graph, the blue columns here show the average capacity factor in 2022 broken out by plant vintage along the x-axis. And what you see here is that, excuse me, after a pretty strong upward trend between 2010 and 2013. Capacity factors have more or less leveled out since then for all vintages since 2013. And that trend can be explained in large part by these same three drivers that I talked about earlier, namely the prevalence of tracking, the DC to AC ratio, and the site quality in terms of solar resource. So from 2010 to 2013, all three of these drivers were moving in the same positive direction, as you can see by these solid lines here.
And that, in turn, pushed capacity factor higher by roughly five percentage points on average. Since then, though, these drivers have been moving somewhat at odds. Most notably, site quality in terms of strength of the solar resource has deteriorated over time. And that is simply a reflection of the industry kind of expanding to less sunny parts of the country. And that is not necessarily a negative thing.
In fact, it can be thought of as a good thing in the sense that. solar is able to compete in less sunny parts of the country, but it does nevertheless have an impact on capacity factor. And it's the primary reason why we see this flat trend here over the last 10 years or so.
If we go to the next slide. Okay. So we can take the capacity factor data that I just ran through in conjunction with the CapEx data that Yo talked about, along with a few other inputs like OPEX, cost of finance, projected useful life. And we can use that information to estimate the levelized cost of energy or LCOE of many plants in our sample.
And then we also collect power purchase agreement prices for a pretty good portion of our sample as well. So let's get into that. So next slide, please. Yeah, so actually, this slide just provides a little bit of information on...
sample size and methodology. For LCOE, we're basically looking at, I think, about 54 gigawatts of plants for which we have LCOE estimates, whereas for PPA prices, our sample is a little smaller. It's about 31 gigawatts. So let's go to the next slide, actually. So here we see the LCOE data.
Each individual bubble here on the graph represents the LCOE of a single plant. with the size of the bubble corresponding to plant capacity. And then the orange columns represent the generation weighted average LCOE. And this is broken out along the x-axis by commercial operation year or plant vintage.
So you can see a pretty strong downward trend. LCOE has fallen by about 84% since 2010 to roughly $39 or $40 per megawatt hour in 2022. And that number does not include the benefit. of the ITC.
Another interesting thing I think you can see on this slide is that the pretty extreme spread or variation in LCOE that we saw back in the early days of the market has really narrowed quite a bit over time. So for example, if you look at 2012, which was a pretty big deployment year, You can see quite a wide range of individual plant level LCOEs there ranging from maybe, I don't know, $70 per megawatt hour up to $350 per megawatt hour. But over time, that range has shrunk quite a bit.
You can contrast that with 2022, where the range, the total range falls into roughly, you know, $50 per megawatt hour range there. And I think that is sort of indicative of a maturing market where... there's greater data transparency and more knowledge about what these projects should actually cost.
So let's go to the next slide. So here we see PPA prices and the graph on the left, which shows our full sample, you can pretty much see the same trend that we just looked at for LCOE as PPA prices have more or less followed LCOE lower over time. So each of the bubbles on this graph represents the...
Levelized PPA price from a single contract with the size of the bubble corresponding to contract capacity and the coloration denoting in which region the plant is located. The left shows our full sample, but the graph over on the right there, I've zoomed into just the most recent years to try to. add a little bit more visibility into what's been going on recently. And there in that graph on the right, you can kind of see this bottoming out in PPA prices around 2019, followed by some stagnation in the year or two after that, and then more recently, a bit of a price increase.
You can also see in this graph on the right that our recent sample is relatively thin. And there are perhaps at least two reasons for that, one being that we tend to collect PPA price data retroactively. And so my guess is that going forward, we'll be able to backfill our 2022 sample a bit more as time passes and more data become available. The second reason is a little bit more interesting, and it reflects the shift in the market away from utility PPAs. towards corporate PPAs.
So as most of you probably know, corporate PPAs are often virtual in nature and are settled financially. And that in turn means that these corporate PPAs are not necessarily subject to the same regulatory reporting requirements that utility PPAs are. And that in turn means that we have less visibility into their pricing.
So our sample is admittedly a little bit thin on reflecting what's going on in the corporate market. But if we go to the next slide, there is a private company, fortunately, out there called Level 10 Energy, who is very deep into the corporate PPA market. They run an online platform that matches up buyers and sellers. And every quarter they publish kind of aggregate price information from what they're seeing on that platform. So that's what I'm showing here in the top two graphs.
These are the prices that Level 10 Energy reports. Down here in the bottom left, that's really where I want to draw your attention here. What I'm doing there is comparing our average PPA price, which are shown here by the, I guess those are tan or brownish columns there.
And I'm comparing them to Level 10's Continental Index, which can be thought of as kind of the average PPA price that they're seeing on their system. And you can see that. But both the levels and the trends between those two data series tend to agree fairly well.
There's a little bit of a gap arising in 2022 as level 10 showed a bit more of an increase than we are. But again, I suspect as we have a chance to kind of backfill our data and flush out our sample a little bit more, that we will probably see a similar increase in pricing in 2022. And then of course the level 10 data foreshadows. a more significant rise into 2023 as well. Next slide. So one additional thing that we can do with our LCOE and PPA price data is to plot them together and see how closely they track one another.
So that's what's shown here. The blue lines show LCOE calculated two ways, both with and without the benefit of the ITC. And then the red line shows our average PPA price. In this case, plotted by commercial operation date as opposed to PPA execution date.
And you can see that PPA prices track LCOE pretty well. In fact, since 2016, the PPA price has very closely tracked the LCOE curve that includes the benefit of the ITC. And this in turn kind of implies that developers are more or less passing through. the value of the ITC to buyers in the form of lower PPA prices. And that is, I think, indicative of a fairly efficient and competitive market.
I guess one other thing to notice here that's kind of interesting is the diminishing dollar value of the ITC over time. And you can see that by the narrowing and the gap between these two blue lines. This makes sense.
I mean, the ITC is a fixed percentage of CapEx. And so as capex declines, so too will the dollar value of the ITC. And if we go to the next slide, this is one reason why we think going forward, many solar developers will exercise their newfound ability to elect the PTC under the Inflation Reduction Act.
So here we've done a bit of heat mapping to kind of reflect this PTC versus ITC tradeoff. We're showing five different heat maps here. because of the bonus tax credits. So there are five different combinations of tax credits that one might think about. Within each heat map, across the top, we're showing a range of capex.
And then down the side, we're showing a range of capacity factor. And in every one of these heat maps, the projects that prefer the ITC are reflected by green shading. So those tend to be the projects that will have a higher capex and a lower capacity factor.
Meanwhile, projects that prefer the PTC are shown in red. Those tend to be those projects that have a lower capex or a higher capacity factor. And...
What we see here in the upper left, that's really our base case scenario where we're looking at just the flat 30% ITC versus the full 100% PTC. So there are no bonus credits in this upper left heat map here. In that case, for your typical utility scale project, given its typical capex and capacity factor range, which are shown by the box in the upper left, we would expect most of those projects to be better off with the PTC, all else being equal.
But as you move to the right, you know, the next two heat maps over to the right start to layer on some of the bonus credits. And in that case, it becomes a little bit more of a toss up. The ITC starts to encroach a little bit. You can see it's shifting to the left and downward, the green shaded area there.
And that is a reflection of the fact that. these adders or bonus credits are worth more to the ITC than they are to the PTC. So in other words, a 10 percentage point increase in the ITC is more than a 10% increase in the PTC.
So, you know, once you get to a project that can layer on both the domestic content and the energy community credit, it's a little bit more of a toss up as to whether PTC or ITC will be preferred. But in general, just going forward, I think we expect to see quite a few projects opting for the PTC. And with that, I think I'm going to turn it back to you now to talk about wholesale market value. Yeah, thanks. Thanks a lot, Mark.
And again, a quick reminder, if you have any questions, please do enter them in the Q&A box. I've been trying to answer a couple of them as we go along to make good use of our time here together. So in this section, we will now analyze. the historical market value of solar generation within the seven organized solar cell power markets that are managed by ISOs across the United States. And then we also use a similar, but somewhat less granular approach to estimate the value of solar for 18 additional non-ISO balancing areas.
And our analysis that we're presenting here focuses on the location-specific marginal energy and capacity value of utility-scale solar. To do that, we have developed plant-level hourly generation estimates that are based on project-specific technical characteristics, as well as the historical irradiance records. And then we debiased those model generation profiles using both ISO-wide hourly solar records, as well as plant-level monthly records.
In the organized wholesale market, solar's energy value represents simply the product of real-time energy prices at the nearest node and the coincident solar generation. Solar's capacity value represents solar's contribution to meeting resource adequacy requirements and it is determined by a project capacity credit that is determined either by the local ELTC methods or other methods that are set up in a particular balancing area. as well as the coincident capacity prices.
This capacity value may be harder to monetize for some solar project owners, in particular outside of regions with a fluid capacity market, and additional performance requirements may be added here, or there may be some other market restrictions that make it a little harder. The total market value that we're presenting here is then simply just the sum of the energy and the capacity values expressed on a pre-containment basis. for those regions where we do have contaminant data.
We thus exclude any potential other revenue streams, such as value from providing ancillary services, renewable energy credit sales, or savings from avoided transmission demand charges, for example, as well as other externalities that are usually not included in wholesale prices, for example, carbon mitigation value. This market value that I'm presenting here can now thus be thought of as revenue that is earned by a merchant solar project from selling its power into the real-time organized market. One of the components that is influencing this effective merchant revenue is the amount of solar energy that is curtailed, either because of system-wide oversupply relative to load or due to local congestion that prevents solar exports to load centers. Unfortunately, we only have two ISOs that are reporting solar curtailment.
In CAISO, we see that solar curtailment has increased again in 2022 to a bit more than 3%. Most of that solar curtailment is concentrated in the spring, when it can exceed up to 80% of the monthly generation. And that often occurs at a time when overall system load is low and generation from hydropower is high. In ERCOT, we have plant-level generation reports that allow us to approximate the curtailment. In 2022, curtailment has surpassed 10% of annual generation and occurs primarily in the fall and in the spring months.
The majority of this curtailment is congestion-driven when generation from western Texas cannot reach. the load centers further in the east. And this may be part of the reason why we now see increasing build-out further east in the state.
On this map, we show the variations in solar value for utility scale plants for the year 2022. The color of the bubble indicates the combined energy and capacity value, while the size of the bubble indicates the capacity size of a given project. On average, across the all of these dots, the solar market value has risen to a record of $71 per megawatt hour in the year 2022 across all the model projects, which is a boost of 40% relative to the prior year of 2021. And this boost has been primarily driven by an increase in natural gas prices. On this map, you can also see how the value varies between regions. It is, for example, rather low in California was $51 per megawatt hour, but higher in the southeastern regions, ranging there from about $85 to $110 a megawatt hour. PGM is also rather high, $85, or ICNU England was $77 per megawatt hour.
But you can also see value differences within a region. So some of this is due to project level variation based on generation profiles due to technological characteristics, for example. but it can also vary due to locational energy and capacity prices.
And again, here transmission constraints can play a role with the associated price volatility. Again, the example here of West Texas, where wholesale market value of solar is lower than in other parts of the state. If you're interested, you can go into much more detail here, again, in interactive visualizations of our website and explore this, these estimates in more detail. We've also posted all the hourly generation profiles of each of the individual model projects on our website, if you want to use them for further modeling analysis. On this slide, we are rolling up the previous plant level specific results into broader regional averages.
The energy value is depicted here in blue, and you can see that it's really the dominant value component in most of the region. The main driver of full-tailed prices and then the associated energy value decline that we observed since 2014 was really natural gas that used to decline for a long time with the shale gas build out but then we saw a moderate increase in 2021 and rapid rise in natural gas price following the Russian invasion in the Ukraine in 2022 and that really lifts up the solar market value here. The capacity value is shown in red and you can see that solar capacity value at the broad range, both between regions, but also over the years within a given region. So while solar's market value has declined historically, at least until the year 2021, we also saw with Mark's presentation that falling PPA prices have largely kept pace, maintaining solar's overall competitiveness.
But especially in 2022, the solar energy and capacity value really... exceeded the level as PPA prices of contracts. So any offtaker who purchased solar power through PPA that was signed in 2022 paid less than what they would otherwise have to pay for purchasing the same amount of power at the same location and time in the smart market of this region. The modest PPA rise that we have observed in response to some of the supply chain constraints and rising interest levels so far seems to have been compensated by four with this large increase in solar value in the last year.
And to provide a little bit more of a sense of whether or not solar provided above or below average value relative to other market participants, one can also compare solar's value with that of the average wholesale energy and capacity prices. And the latter represents the generator that would operate at full capacity in all hours of the year, or what we call the flat block of power. And the ratio of solar's value to the value of that flat block of power power is called the solar value factor and it indicates whether solar provides above or below average market value.
So the solar factor is above or below 100%. This value factor normalizes changes in value that are due to broader trends over time, for example increases in natural gas prices and focuses only on the alignment of the solar profile with times of high wholesale power prices. And it is quite useful, I think, to analyze the effect of increasing solar penetration on solar value.
So you can see that at higher penetration levels, solar's marginal operating costs that are usually near zero dollars per megawatt hour are able to push wholesale prices below where they would be otherwise. And also solar marginal capacity credit usually declines at higher penetrations as the peak node. get shifted increasingly into the late afternoon or early evening hours.
And so you can see that in CAISO in the early days of solar in 2012, when penetration was around 2%, the solar value factor was about 125%. But last year, at a penetration of 26%, it fell down to only 54%. And similar trends exist in much of the West, where other balancing areas either have quite a bit of a high penetration already themselves such as Nevada or Arizona or they're just simply connected to high penetration California through the energy imbalance market and just experience already some of this high penetration rate there for example BPA we see that even low penetration already locally the value factor seems to decline for most of the other ISOs in the southeastern balancing areas, the solar market value is still at really high levels, and that indicates the robust value that solar can provide, particularly at lower penetration levels.
To better understand the origin of value differences between solar generation and a flat block of power, we can differentiate between various effects, the effect of containment, location, and profile. And again, we use this concept of the flat block of power as a starting volunteer that is shown at the bottom of our slide for each of the ISOs in black here. We start by depicting the relative difference between the flat block of power at all pricing nodes in an ISO and those that are just located close to the solar project, and that is shown in gray here. overall for most of the ISOs that has a pretty limited effect. In a second step we then compare the value differences at those solar locations that are driven by solar's generation profile and that is shown here in gold.
And you can see this is clearly the dominant effect and can either be negative as it's the case in CAISO, Iceland, England or it can be highly positive as it is the case in SPT or MISO. Finally, we adjust the solar value downward for reported contaminants in KISO and in ERCOT and that is shown here in the inductive. One way of addressing this value decline of standalone solar as penetrations increase is to simply add storage to a project enabling the owner to shift energy then to higher value periods.
We will only presents the solar specific hybrid data here. If you are interested in broader hybridization trends, for example, solar and wind, or wind and storage, you can see a dedicated report that we've put out on this topic that is linked here. The large scale PV battery hybrid build out started somewhat slowly back in 2016 with just a few projects built each year through 2020. But then it really accelerated dramatically in the year 2021 and kept that pace in 2022. And we see a somewhat even split between new greenfield hybrid developments and retrofits of existing PV projects where now storage gets added.
Most of this new storage was built in Kaisel. We had 13 projects there, more than one gigawatt of storage capacity, on average, three and a half hours of storage duration. Aircon had just three new greenfield hybrids being developed with less storage capacity of just 300 megawatts, and importantly, also shorter duration, on average, just one hour, as the ancillary service market plays. It's kind of more important there.
than really shifting energy from one hour to another, as is the case in Kaizo. Massachusetts has built a lot of smaller projects, but they have only limited storage capacity, 24 megawatts, and often around two hour duration. Looking at the project costs of these projects, we find that the battery cost at our scales in general with the capacity of the battery, of course, and the duration of the battery. And that is shown here in the left graph, where we have combined PV and battery costs for a bit more than 60 projects that were installed over the last five years. You can see if you move along the x-axis to the right, as the capacity of the battery increases, costs kind of go up, and as the battery duration increases with the bubble size going up, the cost can also go up.
For the cost sample for 2022, we have both smaller average battery capacity relative to PV, about 65% on average, and a little bit of a shorter storage duration of just a bit more than two and a half hours relative to what we've seen in 2021. And as a consequence, the mean combined PV and battery costs are now in 2022 a bit lower than they used to be in 2021 at a combined cost of about two. point two dollar twenty or so per watt pv in the in the right graph we now break out component costs for projects where we have such detailed uh data and unfortunately for 2022 we do not yet have enough data to really provide a detailed breakout between the solar and the battery component but for 2021 we can now do that after we received new data from eia in general battery costs are now down to a little more than 700 dollars per kilowatt hour among 21 projects for which we have this data. And the cost of adding a battery to a PV project is about $2 per watt PV, or a little bit more than half of the overall hybrid plant installed cost.
You may be a little confused why the solar component is more costly than for a solar standalone project. That may be because these projects on average have a higher inverter loading ratio. so simply have more modules than what you would otherwise see.
Maybe they are also retrofits to old PV projects when solar standalone projects were simply more expensive. Or maybe there's just simply an uneven accounting of cost between the PV and the battery component. And now I'll hand it back to Mark, who will tell us a little bit more about how these hybrid projects are priced in PPAs. Okay, thank you, Jo.
So just as we collect PPA prices for standalone, solar plants. We also do the same for PV plus storage hybrid plants. And that's what's being shown on these graphs. We're seeing the time trend and PV plus storage PPA prices broken out between plants on the mainland shown here in blue and plants in Hawaii shown in orange. These PPA prices represent the PV and storage components combined.
So you can think of it as an all-in price. But if we go to the next slide, there is a subset of plants that explicitly break out the PV pricing from the storage pricing, which enables us to kind of directly measure the incremental cost of adding a battery to your standalone PV PPA. We show that incremental cost, which we call the levelized storage adder, four different ways on this slide. But just to kind of cut to the chase, given where the time is here, if we look at the bottom right graph, basically you can expect your standalone PV, PPA price to increase by anywhere from, let's say, $10 to $20 to $25 per megawatt hour, depending on how large the battery is relative to the PV capacity. And so I ran through that really quick.
But again, if anyone is interested in this topic, I would point you to a webinar and report that we released about a month ago, which can be found at emp.lbl.gov slash hybrid. And I sent a... I sent that link out in the chat, so hopefully you have that.
Let's go to the next slide, Yo. Yeah, so I do want to take a minute or two to talk about what's coming through the interconnection queues. So let's go to the next slide. Every year we collect data from interconnection queues across the country that includes the seven ISOs or RTOs in addition to 35 more utilities and in aggregate This represents about 85% of all load across the US.
And you can see in the map there the various regions that we're looking at. So we've got pretty good national coverage there. Let's go to the next slide. So here we see data in the queues over time or the amount of capacity in the queues over time.
At the end of 2022, there were 947 gigawatts of solar in the queues. more than a third of this capacity first entered the queues in 2022, so there was a big jump in 2022. Moreover, roughly half of all solar in the queues was paired with a battery, so hybridization is well represented in the queues. If you look over on the left, you can see that solar and storage are really dominating capacity in the queues, followed distantly by wind and even more distantly by gas fire generation. And apart from those four resources, there's really not all that much to speak of in the queues at present. If we go to the next slide, it shows where the 947 gigawatts of solar that's in the queues is located across the U.S.
So a lot of it is in the non-ISO West region, about a quarter of it is located there, but there's also quite a bit in places like MISO and PJM, which might be slightly surprising given that you know, you don't typically think of those two regions as necessarily being all that sunny maybe. If you look at Kaiso, which I guess is fifth from the left, you can see that the vast majority of solar in Kaiso's queue, 97%, is paired with a battery. And the same is true for the West.
The relevant number there is 81%. And this makes some sense because both of these regions obviously have relatively high solar market penetrations. and have been struggling with these duck curve issues that I'm sure you've all heard about.
And so it makes a lot of sense to see strong interest in hybridization in those two areas. Now, although there's a lot of solar capacity in the queues here, keep in mind that only some subset, fairly small subset of this capacity is likely to actually be built in the near future. And I'll just remind you of some graphs that Yo showed earlier in the presentation. projecting maybe somewhere between 20 to 30 gigawatts of solar deployment over the next few years. And so with that, let's just move to the summary slide, Yo.
Let's go to this one. I think we'll leave this up here, but not go through it since we've touched on all these points. And you can read it if you want, but I think we should probably move to a verbal Q&A here with the time we have left. So Yo, do you have any questions queued up there?
Yes. Yeah. So thank you very much for providing questions. I'm not sure that in the remaining few minutes, we'll be able to answer all remaining 12 projects, 12 questions. We'll try to follow up with you after the fact, if we are not able to do that.
There were a couple of questions. One very simple, did we have a standalone storage report recently? No, unfortunately, we're not doing annual market report on standalone.
storage and there are many private consulting companies of course then that do that another question was whether or not we've ever looked at a correlation between maintenance costs or o and m costs in general and capacity factors i think that is a fascinating question one that we have i don't think ever really looked into but i just quickly wanted to given that you asked this question kind of like show you what is what has happened with o and m costs overall over the past years O&M costs have on average declined to now about $10 megawatt hour or sorry $6 megawatt hour per year or $11 per kilowatt year and more recent projects have in general lower O&M expenses than than the old project. So I think we might be able to like do some kind of correlation analysis here but we've not done that recently. I can take one here that I see just came in.
Someone's asking if we conducted an ITC versus PTC comparison for solar plus storage projects. And the answer is no. Solar obviously is now available or eligible for the standalone storage ITC.
There is still some question on or at least I believe there's still some question on whether solar can take the PTC while storage can take the ITC and how it works if you're combining those two assets. So I think we're probably still waiting on some guidance from Treasury on that, although perhaps the lawyers have already taken a view that I'm not aware of. Hey, there are two questions about interconnection studies.
A, why do they take so long? So if you're interested in interconnection like our team, there's a lot of work on that. Actually, there's a whole initiative by the Department of Energy that is called the I2X Initiative that aims to increase the interconnection speed and success chances of solar and wind deployments. I encourage you to check that out.
DOE is also in the process of releasing a roadmap that we've created with them. on this topic, identifying further possible enhancements, and that will be open to public comments. And so I encourage you to look into that. Why do interconnection processes take so long at the moment?
In many of the regions, the process used to be quite convoluted. Not everybody had cluster processes for this. And so it's like one project in front of you dropped out and triggered a lot of restudies.
So overall, it was just not. not very efficient. Furthermore, there are many, many more projects that probably will ever come online and pass because they don't fully know what the interconnection cost at any given node within an ISO will be. And so the only way to have that kind of cost discovery is by submitting a bid, which in turn then increases overall queue size and kind of clocks up the process. BIRC has released some reform proposals on that with a recent rule.
We don't have those incorporated into any of these. forecast. Also, these are not really forecasts where we judge the likelihood of any particular project, but simply report the cues as the various balancing areas happen around the country. So, I think we may see a moderate impact in this year's queued up report, but we will release around March or so of the coming year and can see whether we may see some successes there. Hopefully, overall.
Q will shrink a little bit to more manageable levels and success chances will rise. But I think really the big item out there is about transmission build-out and the recent SOC reforms haven't really touched on that yet. Okay.
So somebody asked about the future of PV plus storage. Will we see more of a build-out? of greenfield plants or retrofits? That's a great question. I think there's a lot of potential for retrofits in this space, and we've certainly seen a fair amount of that already.
So I suspected the answer is probably going to be both. I haven't seen any projections that kind of break out one from the other, but I think you can make a strong case for both. And we are just about at the top of the hour.
I don't know. Do you see any more there, Yo, that we can knock off quickly? Yeah, there was a question of whether or not we're tracking curtailment of coal.
I don't have any coal curtailment data. We do have wind curtailment data, and in many parts of SPP or so, wind curtailment is much stronger than drilling curtailment. There is zero in that region.
If you're interested in particular in wind data, we do have a dedicated report on that topic as well. that you can get at windreport.ldl.gov and I encourage you to look at that. Great. So that does bring us to the end of the hour. So I guess I want to just wrap it up here and thank everybody for sticking with us over the full hour and thanks for all the great questions.
Thanks again to the DOE's Solar Energy Technologies Office for funding this work and we'll be back again next year with the 2024 edition. So thanks, Yo, and everybody have a great day. Thank you very much for your time.