Shared Solar Market Deployment Potential

Industry Insights

This section provides an estimate of the customer market expansion potential that shared solar could provide to the distributed PV market from 2015–2020. The analysis relies upon existing analyst projections of distributed PV installations and infers the additional deployment levels that can be achieved through expanding the available PV system customer base. This section also discusses factors not included in the analysis that could cause the shared solar market to be greater than these estimates.

This analysis does not attempt to calculate the potential rooftop and land area avail- able for shared solar. Several analyses have been conducted previously (Denholm and Margolis 2008; Macknicketal. 2013) showing that the available U.S. rooftop and land area could host hundreds of gigawatts of distributed PV installations; shared solar is merely an ownership structure that can be used to build nearly all of these installations. This analysis assumes that rules and regulations are implemented to allow enough shared solar to  be  deployed  in all states rather than limiting the market potential to states that currently allow VNM or other energy crediting mechanisms. Finally, this analysis relies on market projections of PV system potential across the United States from a variety  of  sources. We did not perform our own independent market projection through detailed market modeling of factors such as renew- able portfolio standard (RPS) requirements, future competitiveness of PV system electricity cost to retail rates, or local supply chains.


Market potential for shared solar was calculated separately for the residential and non-residential PV markets. For each market segment, customers were identified that currently cannot practically host an onsite PV system (either as a PV system owner or through a TPO model).


4.1 Residential Market


Residential customers not able to host a PV system are assumed to meet one of the following criteria: 1) households that do not own their building (i.e., renters), 2) customers in buildings with more than three stories, or 3) those living in a building with insufficient roof space to host a PV system. As shown in Figure 4, the percentage of renters in the U.S. housing market was roughly 50% between 1920–1940 and has been around 35% since the 1970s. Here we assume the percentage of renters remains at 35% over the next decade.


Landlords do not typically purchase the electricity for residential units and may not directly benefit from lower electricity payments. Tenants do not own the properties they inhabit and may not have the ability to authorize an onsite PV array, or, because they are only temporary occupants of the property, long-term investments may not make financial sense. This “split incentive” makes it difficult for either party to   be motivated to purchase a PV system for rental property. Shared solar offers a way for renters to harness the benefits of solar deployment. Shared solar also may be a suitable option for property owners living in buildings without sufficient access to roof space for PV. High-rise buildings and/ or multi-unit housing can present barriers to customers hosting a PV system because individual owners typically do not own a specified portion of the roof space. Additionally, the roof space per household is frequently very small, particularly for high-rise buildings, meaning that the proportional electricity production credit allocation per unit owner will likewise be small. It is also very difficult to install PV systems on buildings with four or more stories because typically the material either has to be brought onto the roof through the interior of the building or outside by special, expensive equipment (such as a crane). As shown in Figure 5, approximately 37% of households are occupied by renters or by owners who live in buildings with four or more stories of the 63% of households that are owner occupied and in a building of less than four stories, we estimated how many of them had sufficient roof space to site a PV system. LiDAR rooftop data from the U.S. Department of Homeland Security were analyzed in 167 U.S. regions (see map in Appendix E). The data processed cover an area with a population of 100.1 million (33%  of  the  population  of  the  lower 48 states) and roof area of 7.7 billion square meters, including 13.1 million city buildings and 13.8 million rural and suburban buildings.24 Data were unavailable to deter- mine which buildings within the data set were “residential.” Therefore, those with a footprint less than 5,000 square feet were assumed to be “residential” based on previous analysis from Ongetal. (2012).As an initial step, the data were analyzed to determine how many buildings  meet the following requirements to host a PV system:


• Shade and slope thresholds enabling PV modules to receive sunlight for an acceptable period

• A roof facing flat, south, east, southeast, west, or southwest -also to ensure that PV modules receive sunlight for an acceptable period

• A minimum of 10 square meters of contiguous area meeting the above requirements.



It is estimated that 10 square meters of contiguous roof space are sufficient to install a 1.5-kW PV system, assuming an average module efficiency of 15%, which  is in line with 2014 average multicrystalline module efficiencies of 15%–16% (Munsell 2014). The 1.5-kW system threshold was chosen because a significant portion of U.S. residential systems are installed at or below this capacity. Although residential systems can range significantly in size, they are typically assumed to be less than or equal to 10 kW in capacity (Sherwood 2014). While the average size of systems less than or equal to 10 kW is 4.9 kW, 19% of the systems have capacities between 1.5 kW and 3 kW, as shown in Figure 6.


This indicates that setting the threshold at 3 kW versus 1.5 kW would exclude 19% of currently installed U.S. systems sized at 10 kW or less. Further, DOE’s A Guide to Community Solar estimates the average size of a customer’s portion of a shared solar installation is between 0.5 kW and 4 kW (Coughlinetal. 2010), and SEPA’s recent survey of community solar programs found that the average residential participant purchased 1.7 kW of capacity (Campbelletal. 2014).


Based on the thresholds outlined above, the analysis indicates that 81% of residential buildings have enough suitable roof space to host a 1.5-kW PV system.27 Some variability exists within the data depending on the region of the country. For example, given a minimum threshold of 10 square meters, only 73% of residential buildings in the Northwest satisfy the minimum thresh - old requirements outlined above compared to 86% of residential buildings in the Southwest.


When accounting for a residential building’s ownership, number of stories, and availability and suitability of roof  space, we estimate that only 51% of households can install a 1.5-kW PV system.28 In other words, shared solar has the potential to double the residential market by offering PV to the 49% of households that—owing to shading, roof suitability and size, or ownership—cannot host a PV system.


To assess the near-term market potential of onsite residential PV, we collected analyst projections of the U.S. residential market. These estimates project until the year 2017, after which we kept demand constant, as shown in Figure 7.


While shared solar has the potential to double the residential PV market (as outlined above), net metering caps, limited state PV incentives, and the growth rate of this new financial business model are likely to bound deployment in the next five years. Net metering, as discussed in Section 3, is a billing mechanism that allows customers to receive credit on their utility bills for energy generated from a PV system. Net metering caps limit the total amount of net metered generating capacity that can be installed in a state or utility service territory. A recent National Renewable Energy Laboratory (NREL) report found that a little over half of states with net metering policies have caps on their net metered capacity; several more states without caps have triggers that enable net metering to be reviewed. The report also found that “a handful of states could reach current cap levels by 2018” (Heeteretal. 2014, page 33).


At the state level, the RPS has proven to  be  one  of  the  most  significant  drivers  of renewable energy deployment in the United States. An RPS, also called a renewable electricity standard (RES), requires electricity suppliers to purchase or generate a targeted amount of renewable energy by a certain date. Although design details can vary considerably, RPS policies typically enforce compliance through penalties, and many include the trading of renew- able energy certificates (RECs). As shown  in Figure 8, 23 states and  Washington,  DC, had RPS policies  with  specific  solar or distributed-generation provisions as of September 2014 (DSIRE 2014).



As an alternative to RECs, states have incentivized PV deployment through upfront cash grants, performance-based cash grants, state and local tax credits, and feed-in tariffs. Local jurisdictions without strong state solar mandates (e.g., Austin, TX) have developed solar initiatives  as  well. These programs either have limited funding or respond to market oversupply relative to RPS requirements; therefore, a portion of future PV demand is limited by incentives and RPS mandates.  This  may  be particularly relevant post-2016, when the 30% federal residential ITC expires, the federal commercial ITC is reduced to 10%, and projects must rely more heavily on state funding or revenue through the trading of RECs.


Recently, PV systems have been installed in certain U.S. markets (e.g., Hawaii, California) without the need for state or local incentives, either because of relatively high retail electricity rates in those markets, relatively low system costs, or a combination of both factors. As shown in Figure 9, in the fourth quarter of 2013, only 37% of distributed PV systems installed in California received assistance from the California Solar Initiative (CSI), the state’s largest incentive program. This was down from 89% just 2 years earlier, while the overall capacity of distributed PV systems installed in California has grown substantially over the same period.


As state and local incentive programs wind down or exhaust their budgets, many analysts expect a larger share of systems to be installed with only the federal incentives. However, given that many systems are still expected to require state incentives (with limited budgets) to be financially viable, and that net metering caps may also constrain distributed PV in certain areas, we model two scenarios:  one  in  which  50% of U.S. distributed PV demand is capped  by these factors (i.e., 50% of the market will not grow despite the potential for new customers provided by shared solar pro- grams), and one in which future demand  is not capped by these potential limitations.


To estimate the rate at which it  takes  a new financial business model to develop fully within the residential PV market, we examined the time it took the TPO business model to reach its peak percentage of the market.30 Residential TPO, which in large part started in 2006 with the founding of SolarCity, solved many of the barriers to PV adoption for homeowners. However, it took 6 years for TPO’s market share to reach a relatively steady state (Figure 10).


The shared solar marketplace will need to develop in many of the same ways that the TPO market developed, such as expanding shared solar businesses nationwide, promoting customer awareness of a new financial product, and changing some state and local laws to accommodate the new business models. We assume shared solar will go through this growth process over a similar period, estimating that the residential shared solar market will require 6 years (from 2015–2020) to reach full maturity, growing from 15% of its potential in years 1–3 to 35% in year 4, 65% in year 5, and 100% in year 6.


We calculated the market potential of shared solar for 2015–2020 with the data sets described above using the following equation:


Based on these assumptions, we estimate that, from 2015–2020, cumulative shared solar installations could constitute 3.1–6.3 GW of PV for residential customers, includ- ing 1.3–2.6 GW in 2020 alone (Figure 11). This  could  represent  an  additional  $4.7–

$9.3 billion of cumulative investment.


Credits: National Renewable Energy Laboratory (NREL)


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