TODAY’S STUDY: The Trends In Distributed Solar Pricing and Placement

Tracking the Sun; Pricing and Design Trends for Distributed Photovoltaic Systems in the United States, 2019 Edition

Galen Barbose, Naïm Darghouth, et al, October 2019 (Lawrence Berkeley National Laboratory [LBNL])

Executive Summary

Lawrence Berkeley National Laboratory (LBNL)’s annual Tracking the Sun report summarizes installed prices and other trends among grid-connected, distributed solar photovoltaic (PV) systems in the United States. 1 This edition focuses on systems installed through year-end 2018, with preliminary trends for the first half of 2019. As in years past, the primary emphasis is on describing changes in installed prices over time and variation across projects. This year’s report also includes an expanded discussion of other key technology and market trends, along with several other new features, as noted in the text box below.

Trends in this report derive from projectlevel data reported primarily to state agencies and utilities that administer PV incentives, renewable energy credit (REC) registration, or interconnection processes. In total, data were collected and cleaned for 1.6 million individual PV systems, representing 81% of all U.S. distributed PV systems installed through 2018. The analysis of installed prices is based on the subset of roughly 680,000 host-owned systems with available installed price data, of which 127,000 were installed in 2018. A public version of the full dataset is available at trackingthesun.lbl.gov.

Numerical results are denoted in direct current (DC) Watts (W) and real 2018 dollars. Non-residential systems are segmented into small vs. large nonresidential, based on a cut-off of 100 kW.

Distributed PV Project Characteristics. Key technology and market trends based on the full dataset compiled for this report are as follows.

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• PV systems continue to grow in size, with median sizes in 2018 reaching 6.4 kW for residential systems and 47 kW for non-residential systems. Sizes also vary considerably within each sector, particularly for non-residential systems, for which 20% were larger than 200 kW in 2018.

• Module efficiencies continue to grow over time, with a median module efficiency of 18.4% across all systems in the sample in 2018, a full percentage point increase from the prior year.

• Module-level power electronics—either microinverters or DC optimizers—have continued to gain share across the sample, representing 85% of residential systems, 65% of small nonresidential systems, and 22% of large non-residential systems installed in 2018.

• Inverter-loading ratios (ILRs, the ratio of module-to-inverter nameplate ratings) have generally grown over time, and are higher for non-residential systems than for residential systems. In 2018, the median ILR was 1.11 for residential systems with string inverters and 1.16 for those microinverters, while large non-residential systems had a median ILR of 1.24.

• Roughly half (52%) of all large non-residential systems in the 2018 sample are groundmounted, while 7% have tracking. In comparison, 17% of small non-residential systems and just 3% of residential systems are ground-mounted, and negligible shares have tracking.

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• Panel orientation has become more varied over time, with 57% of systems installed in 2018 facing the south, 23% to the west, and most of the remainder to the east.

• A small but increasing share of distributed PV projects are paired with battery storage, typically ranging from 1-5% in 2018 across states in our dataset, though much higher penetrations occurred in Hawaii and in a number of individual utility service territories.

• Third-party ownership (TPO) has declined in recent years, dropping to 38% of residential, 14% of small non-residential, and 34% of large non-residential systems in the 2018 sample.

• Tax-exempt customers—consisting of schools, government, and nonprofit organizations— make up a disproportionately large share (roughly 20%) of all 2018 non-residential systems.

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Temporal Trends in Median Installed Prices. The analysis of installed pricing trends in this report focuses primarily on host-owned systems. Key trends in median prices, prior to receipt of any incentives, are as follows.

• National median installed prices in 2018 were $3.7/W for residential, $3.0/W for small nonresidential, and $2.4/W for large non-residential systems. Other cost and pricing benchmarks tend to be lower than these national median values, and instead align better with 20th percentile values (see Text Box 5 in the main body for further discussion of these issues).

• Over the last full year of the analysis period, national median prices fell by $0.2/W (5%) for residential, by $0.2/W (7%) for small non-residential, and by $0.1/W (5%) for large nonresidential systems. Those $/W declines are in-line with trends over the past five years.

• Over the longer-term, since 2000, installed prices have fallen by $0.5/W per year, on average, encompassing a period of particularly rapid declines (2008-2012) when global module prices rapidly fell. In many states, the long-term drop in (pre-incentive) installed prices has been substantially offset by a corresponding drop in rebates or other incentives.

• Preliminary and partial data for the first half of 2019 show roughly a $0.1/W drop in median installed prices compared to the first half of 2018, though no observable drop relative to the second half of 2018. Those trends are based on a subset of states, consisting of larger markets, where price declines have recently slowed compared to other states.

• Installed price declines reflect both hardware and soft-cost reductions. Since 2014, following the steep drop in global module prices, roughly 64% of the total decline in residential installed prices is associated with a drop in module and inverter price, while the remaining 36% is due to a drop in soft costs and other balance-of-systems (BoS) costs. For nonresidential systems, a slightly higher percentage of total installed price declines is attributable to BoS and soft costs.

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Variation in Installed Prices.

This report highlights the widespread variability in pricing across projects and explores some of the drivers for that variability, focusing primarily on systems installed in 2018. The exploration of pricing drivers includes both basic descriptive comparisons as well as a more formal econometric analysis. Key findings include the following.

• Installed prices in 2018 ranged from $3.1-4.5/W for residential systems (based on the 20th and 80th percentile levels), from $2.4-4.0/W for small non-residential systems, and from $1.8-3.3/W for large non-residential systems.

• Installed prices within each customer segment vary substantially depending on system size, with median prices ranging from $3.3-4.3/W for residential, from $2.7-3.4/W for small nonresidential, and from $2.0-3.6/W for large non-residential systems, depending on size.

• Installed prices also vary widely across states, with state-level median prices ranging from $2.8-4.4/W for residential, $2.5-3.7/W for small non-residential, and $1.7-2.5/W for large non-residential systems.

• Across the top-100 residential installers in 2018, median prices for each individual installer generally ranged from $3.0-5.0/W, with most below $4.0/W.

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• Median prices are notably higher for systems using premium efficiency modules (>20%) and for systems with microinverters or DC optimizers. Comparisons between residential retrofits and new construction, and comparisons based on mounting configuration, are both less revealing, likely due to relatively small underlying sample sizes.

• The multi-variate regression analysis, which focuses on host-owned residential systems installed in 2018, shows relatively substantial effects associated with system size (a $0.8/W range between 20th and 80th percentile system sizes) and with other system-level factors, including those related to module efficiency (+$0.2/W for systems with premium efficiency modules), inverter type (+$0.2/W for systems with either microinverter or DC-optimizers), ground-mounting (+$0.3/W), and new construction (-$0.5/W).

• In comparison, the regression analysis found relatively small effects for various market- and installer-related drivers—including variables related to market size (a $0.2/W range between the 20th to 80th percentile values for market size), market concentration (a $0.1/W range), household density (a $0.2/W range), average household income (no effect), and installer experience (no effect).

• After controlling for various system-, market-, and installer-level variables, the regression analysis still found substantial residual pricing differences across states (a $1.5/W range), indicating that other, unobserved factors significantly impact installed prices at the state- or local-levels.

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Declining State and Utility Cash

Incentives Financial incentives provided through utility, state, and federal programs have been a driving force for the PV market in the United States. For residential and non-residential PV, those incentives have—depending on the particular place and time—included some combination of cash incentives provided through state and/or utility PV programs (rebates and performance-based incentives), the federal investment tax credit (ITC), state ITCs, revenues from the sale of solar renewable energy certificates (SRECs), accelerated depreciation, and retail rate net metering.

Focusing solely on direct cash incentives provided in the form of rebates or performance-based incentives (PBIs), Figure 18 shows how these incentives have declined steadily and significantly over the past decade. At their peak, most programs were providing incentives of $4-8/W (in real 2018 dollars). Over time, direct rebates and performance-based incentives have been largely phased-out in the larger state markets—including Arizona, California, Massachusetts, and New Jersey—and have diminished to below $0.5/W in most other locations. This continued ratcheting down of incentives is partly a response to the steady decline in the installed price of PV and the emergence of other forms of financial support (for example, SRECs, as discussed in Text Box 4). At the same time, incentive declines may have also helped to motivate further cost and price reductions, as installers were forced to cut costs to remain competitive. The steady ratcheting down of incentives has thus likely been both a cause and an effect of long-term installed price reductions.

From the perspective of the customer-economics of PV, however, one thing is clear: the steady reduction in cash incentives has offset reductions in (pre-incentive) installed prices to a significant degree. Among the five state markets profiled in Figure 18, the decline in incentives from each market’s respective peak is equivalent to anywhere from 66% to 100% of the drop in installed PV prices over the corresponding time period. Of course, other forms of financial support have simultaneously become more lucrative over this period of time—for example, the federal ITC for residential solar rose in 2009, and SREC markets emerged in many states; new financing structures have also allowed greater monetization of existing tax benefits. And while net metering rules and rate design for solar PV customers have come under greater scrutiny, most of the large state markets have yet to make any substantial changes to those structures. The customer economics of solar in many states thus has likely improved, on balance, over the long-term, but the decline in state and utility cash incentives has nevertheless been a significant counterbalance to falling installed prices.

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