MONDAY’S STUDY: Big Solar Right Now
Utility-Scale Solar; Empirical Trends in Project Technology, Cost, Performance, and PPA Pricing in the United States – 2019 Edition
Mark Bolinger, Joachim Seel, Dana Robson, January 2020 (Lawrence Berkeley National Laboratory)
The utility-scale solar sector—defined here to include any ground-mounted photovoltaic (“PV”), concentrating photovoltaic (“CPV”), or concentrating solar-thermal power (“CSP”) project that is larger than 5 MWAC in capacity—has led the overall U.S. solar market in terms of installed capacity since 2012. In 2018, the utility-scale sector accounted for nearly 60% of all new solar capacity, and is expected to maintain its market-leading position for at least another five years, driven in part by favorable Internal Revenue Service (“IRS”) “safe harbor” guidance that enables projects that start construction in 2019 to qualify for the 30% federal investment tax credit (“ITC”) if they achieve commercial operations prior to 2024. With four new states—Washington, Wyoming, Vermont, and Connecticut—having added their first utility-scale solar project in 2018, three quarters of all states, representing all regions of the country, are now home to one or more utility-scale solar projects. This ongoing solar boom makes it challenging—yet more important than ever—to stay abreast of the latest utility-scale market developments and trends.
This report—the seventh edition in an ongoing annual series—is intended to help meet this need, by providing in-depth, annually updated, data-driven analysis of the utility-scale solar project fleet in the United States. Drawing on empirical project-level data from a wide range of sources, this report analyzes not just installed project prices—i.e., the traditional realm of most solar economic analyses—but also technology trends, operating costs, capacity factors, power purchase agreement (“PPA”) prices, levelized cost of energy (“LCOE”), curtailment, and market value from a large sample of utility-scale solar projects throughout the United States. The report also includes data and observations about completed or recently announced solar+storage projects. Given its current dominance in the market, utility-scale PV also dominates much of this report, though data from CPV and CSP projects are also presented where appropriate.
Some of the more-notable findings from this year’s edition include the following:
• Installation and Technology Trends: Among the total population of utility-scale PV projects from which data samples are drawn—i.e., 690 projects totaling 24,586 MWAC—several trends are worth noting due to their influence on (or perhaps reflection of) the cost, performance, and PPA price data analyzed later. For example, the use of solar trackers (all single-axis, east-west tracking) dominated 2018 installations, with nearly 70% of all new capacity. Fixed-tilt projects are increasingly only built in less-sunny regions, while tracking projects continue to push into these same regions. After declining for five consecutive years—a reflection of the geographic shift in the market from the high-insolation Southwest to other less-sunny regions—the median long-term average insolation at newly built project sites stabilized in 2018. Meanwhile, the median inverter loading ratio (“ILR”)—i.e., the ratio of a project’s DC module array nameplate rating to its AC inverter nameplate rating—has grown steadily since 2014, to 1.33 in 2018 for both tracking and fixed-tilt projects, allowing the inverters to operate closer to (or at) full capacity for more of the day. In 2018, seven utility-scale PV+battery projects came online.
• Installed Prices: Median installed PV project prices within an overall sample of 641 projects totaling 22,886 MWAC have steadily fallen by two-thirds since the 2007-2009 period, to $1.6/WAC among 60 projects completed in 2018 and totaling 2,499 MWAC. The lowest 20th percentile of projects within this 2018 sample were priced at or below $1.3/WAC, with the lowest-priced projects around $1.0/WAC. Those 2018 projects that use single-axis trackers exhibited no upfront cost premium (and even slightly lower prices) compared to fixed-tilt installations. Overall price dispersion across the entire sample has decreased steadily every year since 2013.
• Operation and Maintenance (“O&M”) Costs: What limited empirical O&M cost data are publicly available suggest that PV O&M costs were in the neighborhood of $19/kWAC-year, or $11/MWh, in 2018. These numbers—from a limited sample of 48 projects totaling 919 MWAC—include only those costs incurred to directly operate and maintain the generating plant, and should not be confused with total operating expenses, which would also include property taxes, insurance, land royalties, performance bonds, various administrative and other fees, and overhead.
• Capacity Factors: The cumulative net AC capacity factors of individual projects in a sample of 550 PV projects totaling 20,024 MWAC range widely, from 12.1% to 34.8%, with a sample median of 25.2% and a capacity-weighted average of 27.0%.1 This project-level variation is based on a number of variables, including the strength of the solar resource at the project site, whether the array is mounted at a fixed tilt or on a tracking mechanism, the ILR, degradation, and curtailment. Changes in at least the first three of these factors drove mean capacity factors higher from 2010-vintage (at 21.7%) to 2013-vintage (at 26.7%) projects. Among more-recent project vintages, however, mean capacity factors have remained stagnant or even declined, as a build-out of lower-resource sites has offset an increase in the prevalence of tracking (while the ILR has changed little).
• PPA Prices and LCOE: Driven by lower installed project prices and, at least through 2013, improving capacity factors, levelized PPA prices for utility-scale PV have fallen dramatically over time, by $20-$30/MWh per year on average from 2006 through 2012, with a smaller price decline of ~$10/MWh per year evident in most years since 2013. Aided by the 30% ITC, most recent PPAs in our sample—including many outside of California and the Southwest—are priced below $40/MWh levelized (in real 2018 dollars), with many priced below $30/MWh and a few even priced below $20/MWh. Despite these low PPA prices, solar continues to face stiff competition from both wind and natural gas. Excluding the benefit of the 30% ITC, the median LCOE among operational PV projects in our sample stood at $53.8/MWh in 2018 (with a range from $33.8/MWh to $112.8/MWh), and has followed PPA prices lower over time, suggesting a relatively competitive market for PPAs.
• Solar’s Wholesale Market Value: Falling PPA prices have been matched to some degree by a decline in the wholesale market value of solar (energy + capacity) within higher-penetration solar markets like California. Due to an abundance of solar energy pushing down mid-day wholesale power prices, solar generation in California earned just 79% of the average energy and capacity price within CAISO’s wholesale market in 2018 (down from 146% back in 2012). In five of the six other ISO markets analyzed, however, solarstill provides above-average value (the exception being ISO-NE, at 89% of average wholesale market value in 2018). In CAISO, falling solar PPA prices have largely kept pace with solar’s declining market value over time, thereby maintaining solar’s competitiveness. In all other ISOs, solar offers higher value yet, in some cases, similar or even lower PPA prices than in California, which may be one reason why the market has been shifting away from California and into other regions.
• Solar+Storage: Adding battery storage is one way to increase the value of solar, and a proliferation of PV plus storage PPAs and project announcements over the past few years has provided a critical mass of concrete data for us to begin tracking. Data from 38 completed or announced PV hybrid projects totaling 4.3 GWAC of PV and 2.6 GWAC of battery capacity (and with storage duration ranging from 2-5 hours, with 4 hours being by far the most common) suggests that sizing of the battery capacity relative to the PV capacity varies widely, depending on the application and specific situation. Moreover, the size of the incremental PPA price adder for 4-hour storage varies linearly with this ratio, ranging from ~$5/MWh for batteries sized at 25% of PV capacity up to $15/MWh for batteries sized at 75% of PV capacity. There are a variety of ways in which storage is compensated within these PPAs, some of which are rather creative (see the discussion following Table 3 in Section 2.5). As PV plus battery storage becomes more cost-effective, many developers are now regularly offering it as an upgrade to standalone PV.
• CSP: No new utility-scale CSP projects have come online in the United States since 2015, and no CSP plants are currently under construction or in late-stage development. As such, the only new CSP data reported in this 2019 edition relates to the capacity factors of existing CSP plants. On that front, two recent trough projects without storage have largely matched ex-ante capacity factor expectations, while two power tower projects and a third trough project with storage continue to underperform relative to projected long-term, steady-state levels. Further details are provided in Chapter 3.
Looking ahead, the amount of utility-scale solar capacity in the development pipeline suggests continued momentum and a significant expansion of the industry in future years. At the end of 2018, there were at least 284 GW of utility-scale solar power capacity within the interconnection queues across the nation, 133 GW of which first entered the queues in 2018 (with 36 GW of this 133 GW including batteries). The growth within these queues is widely distributed across all regions of the country, and is most pronounced in the up-and-coming Midwest region, which accounts for 26% of the 133 GW, followed by the Southwest (21%), Southeast and Northeast (each with 15%), California (10%), Texas (9%), and the Northwest (5%). Though not all of these projects will ultimately be built as planned, the ongoing influx and widening geographic distribution of solar projects within these queues is as clear of a sign as any that the utility-scale market is maturing and expanding outside of its traditional high-insolation comfort zones.
Finally, we’ve set up several data visualizations that are housed on the home page for this report: https://utilityscalesolar.lbl.gov. There you can also find an Excel workbook that features the underlying data for each of the report’s figures, a slide deck, and a post-release webinar recording…
Conclusions and Future Outlook
This seventh edition of LBNL’s annual Utility-Scale Solar series paints a picture of an increasingly competitive utility-scale PV sector, with installed prices having declined significantly over the past decade, enabling record-low PPA prices of under $20/MWh (levelized, in real 2018 dollars) in a few cases and under $30/MWh on average—even in areas outside of the traditional strongholds of California and the Southwest. Meanwhile, the other principal utility-scale solar technology, CSP, has also made strides in the last decade—e.g., deploying several large projects featuring new trough and power tower technologies and demonstrating thermal storage capabilities—but has struggled to meet performance expectations in some cases, and is otherwise finding it difficult to compete in the United States with increasingly low-cost PV. As a result, there were no new CSP projects either online or under construction in 2018, and one existing project had its PPA cancelled due to underperformance.
Looking ahead, analyst projections, as well as data on the amount of utility-scale solar capacity in the development pipeline, suggest a significant expansion of the industry in the coming years—in terms of both volume and geographic distribution. For example, Figure 37 and Figure 38 show the amount of solar power (and, in Figure 37, other resources) working its way through 37 different interconnection queues administered by independent system operators (“ISOs”), regional transmission organizations (“RTOs”), and utilities across the country as of the end of 2018. 71 Although placing a project in the interconnection queue is a necessary step in project development, being in the queue does not guarantee that a project will actually be built72—as a result, these data should be interpreted with caution. That said, efforts have been made by the FERC, ISOs, RTOs, and utilities to reduce the number of speculative projects that have, in previous years, clogged these queues, and despite its inherent imperfections, the amount of solar capacity in the nation’s interconnection queues still provides at least some indication of the amount of planned development.
At the end of 2018, there were 284 GW of solar power capacity (of any type—e.g., PV, CPV, or CSP) within the interconnection queues reviewed for this report—more than ten times the installed utility-scale solar power capacity in our entire project population at that time. These 284 GW—133 GW of which first entered the queues in 2018—represented 44% of all generating capacity within these selected queues, opening up solar’s lead on both wind power at 36% and natural gas at 13% (see Figure 37). The end-of-2018 solar total is also 95 GW higher than the 189 GW of solar that were in the queues at the end of 2017, demonstrating that the solar pipeline was more than replenished in 2018, despite the 4 GWAC of new solar capacity that came online (and therefore exited these queues) in 2018. Finally, this year we’ve also tallied the amount of solar (and other resources) in the queues that is paired with battery storage as a hybrid project; as indicated by the hatched area in Figure 37, solar leads the pack with 55 GW of PV hybrid capacity (compared to just 5 GW of wind hybrid capacity).73 Standalone storage capacity has also continued to grow in the queues, to 28 GW at the end of 2018.
Figure 38 breaks out the solar (and PV hybrid) capacity by state or region, to provide a sense of where in the United States this pipeline resides (as well as how that composition has changed going back to 2014). As shown, solar capacity in the queues is now much more evenly distributed across the country than it was just three years ago. For example, at the end of 2015, 42% of all solar capacity in the queues was located in California, compared to just 16% at the end of 2018. Moreover, 2018 was the first year in which California (with 44 GW) did not lead the country in terms of solar capacity in the queues, having been supplanted by the meteoric rise of the Midwest (64 GW), while also falling behind the Southwest (54 GW). Meanwhile, the Southeast, Texas, and the Northeast were all essentially tied at ~36 GW. This notable expansion of utility-scale solar development to regions beyond California and the Southwest is indicative of a maturing market that is capitalizing on solar’s increasing competitiveness across the country.
As with Figure 37, the hatched portion of each column in Figure 38 shows the amount of solar capacity that is paired with a storage as a hybrid project. More than 75% of the 55 GW of PV hybrid capacity in the queues at the end of 2018 is in the Southwest (49%) and California (26%)— two high-penetration regions that are grappling with “duck curve” issues that can be at least partly alleviated by storage.74
Though not all of these 284 GW of planned solar and PV hybrid projects represented in Figure 37 and Figure 38 will ultimately be built, Figure 1 at the start of this report showed that analysts do expect historically strong deployment of roughly 11 GW per year of utility-scale solar through at least 2024, driven in part by ongoing access to the 30% ITC through 2023 (as a result of favorable “safe harbor” guidance from the IRS), coupled with utility-scale PV’s declining costs. Of course, accompanying all of this new solar capacity will be substantial amounts of new cost, price, and performance data, which we plan to collect and analyze in future editions of this report.