Over the last decade, the costs of residential solar photovoltaic (PV) systems in the U.S. have steadily declined, and many stakeholders – including homeowners, utilities and regulators – are increasingly considering the value of energy storage tied to PV systems. How can distributed energy storage enhance grid operations? Is it cost-effective? How will costs evolve over time? Today, the answers to many of these questions largely depend on where the PV+storage system is installed. Locality-specific costs and processes like permitting, interconnection, net metering, and fire codes can vary widely across the U.S., affecting not only project costs, but also project timelines. Some of the biggest variables affecting the financial viability of grid-connected PV+storage projects are the local utility rates, incentives and how ancillary benefits of the systems are valued.
Kristen Ardani
New research from the U.S. Department of Energy’s (DOE) National Renewable Energy Laboratory (NREL) and the DOE’s SunShot Initiative is shedding light on some of the barriers preventing widespread deployment of PV+storage systems. Summarized in a new report, “Installed Cost Benchmarks and Deployment Barriers for Residential Solar Photovoltaics with Energy Storage: Q1 2016,” the research offers insights that could help lower those barriers.
Broadly speaking, our report focuses on two main types of barriers to residential energy storage deployment: cost barriers and value barriers.
With respect to cost, although storage technology costs continue to decline, today’s installed system prices – which include non-hardware costs, such as customer acquisition, permitting, overhead and interconnection – remain relatively high for a typical homeowner. Previously, few studies have offered detailed, installed system price breakdowns for distributed storage. This lack of publicly available information limits our understanding of the main cost drivers and cost-reduction opportunities. Our report fills this gap in the research literature by providing granular installed system price breakdowns that include previously unknown non-hardware costs, such as those associated with the regulatory approval process.
With respect to value, the absence of actual markets in most parts of the U.S. for distributed energy storage services prevents utilities and storage owners from realizing the full value of energy storage and undermines the overall economics. While our report focuses on offering an extensive analysis of the system and component cost barriers, it also offers insights into the value barriers facing PV+storage.
Regular benchmarking and tracking of system prices and component costs can help provide insight into underlying cost drivers. Since 2009, analysts at NREL have annually benchmarked installed PV system prices for the residential, commercial and utility-scale sectors. NREL’s methodology includes bottom-up accounting for all component and project-development costs incurred when installing PV systems, excluding the investment tax credit (ITC). As the prices of these systems have fallen, NREL’s benchmarking analysis has shown the importance of reducing non-hardware costs to achieving the DOE SunShot Initiative’s cost and deployment targets by 2020 – and has revealed new opportunities to reduce costs even further.
Now, for the first time, NREL and SunShot have established granular system price benchmarks for residential PV+storage systems installed in the first quarter of 2016 (Q1’16). One aim of the report was to help technology manufacturers, installers, and other stakeholders identify cost-reduction opportunities and inform decision-makers about regulatory, policy, and market characteristics that impede PV+storage deployment.
For our PV+storage benchmarking, we adapted NREL’s proven approach for residential, stand-alone PV systems and model the cash purchase price, excluding the federal ITC. In general, we attempt to model typical installation techniques and business operations with an approach that enables benchmarking of costs independent from price, which is critical in understanding industry progress in reducing costs over time. Our methodology provides a granular accounting for all direct and indirect costs and captures variation driven by multiple factors. For example, we capture cost variation driven by different system designs, product specifications, and the intended end use of installed storage capacity. The results of this original analysis and modeling were compared to a review of the published literature and validated through interviews with more than 22 industry and subject matter experts.
All of our hardware benchmarks represent the price at which components are purchased by the installer and represent the product offerings most commonly available today on a national average basis. Future work will expand the benchmarking analysis to account for geographic variability and regional trends, which will be especially important as new, lower-cost technologies become more widely available in specific markets.
We applied a 17% fixed margin to represent the net profit of the installer. Our analysis did not include any additional price gross-up or adders, which are common in the marketplace today. We used this approach because of the wide variation in installer profits in the residential sector, where end-user pricing is highly dependent on the region, local retail electricity rates, local rebates and incentives, competitive environment, and overall project or deal structures.
Analyzing storage system pricing and component costs presents the additional challenge of choosing an appropriate metric to use in adapting NREL’s stand-alone PV cost-modeling approach. Stand-alone PV has several standard metrics, such as dollars per watt ($/W) of installed capacity or levelized cost of energy (LCOE); however, energy storage lacks a similar, widely accepted metric.
Storage systems are designed for a variety of different customer needs that drive whether the cost per unit of power (dollars per kilowatt, $/kW) or cost per unit of energy (dollars per kilowatt-hour, $/kWh) storage capacity is more relevant for a given customer. In general, customers who have loads with high peaks of short duration may desire a high-power (kW) battery capable of meeting the high peak. Customers who have flatter loads with lower peaks of longer duration may prefer a high-energy (kWh) battery capable of longer-duration energy discharge. We decided to use total installed price of a typical PV+storage system as our primary metric, and we compared that metric across several different system configurations.
We considered four major characteristics when evaluating PV+storage systems:
• PV system capacity (in kW);
• Battery energy capacity (in kWh);
• Battery power capacity (in kW); and
• Whether the battery is direct-current (DC) or alternating-current (AC) coupled.
AC-coupled systems are generally more efficient in applications where PV energy is mostly consumed at the time of generation. DC-coupled systems are more efficient in applications where PV energy is mostly stored for use at a later time. However, future technological improvements that eliminate the need for the charge controller or increase the efficiency of battery-based inverters could reduce the efficiency gap between DC- and AC-coupled systems.
We also considered two different battery sizes: a “small-battery case” and a “large-battery case.” The small-battery case – which uses a 5.6 kW PV array and a 3 kW/6 kWh lithium-ion battery system – is designed to enable a typical customer to optimize self-consumption of PV electricity, including peak-demand shaving and time-of-use shifting, and to provide backup power for a limited number of critical loads in the event of a grid outage. The large-battery case – which uses a 5.6 kW PV array and a 5 kW/20 kWh lithium-ion battery system – is designed to optimize self-consumption of PV electricity and to meet greater backup power (kW) and energy (kWh) requirements in the event of a grid outage.
In total, we selected and analyzed the costs of five PV+storage systems. Their benchmarked costs for Q1’16 were the following:
• “Small-battery case,” DC coupled – $27,703;
• “Small-battery case,” AC coupled – $29,568;
• “Small-battery case,” AC coupled, battery retrofitted to system – $32,786;
• “Large-battery case,” DC coupled – $45,237; and
• “Large-battery case,” AC coupled – $47,171.
For comparison, the benchmarked cost for Q1’16 of a stand-alone 5.6 kW PV system was $15,581.
Some interesting observations have emerged. For example, our work shows that the benchmarked price of a typical residential PV+storage system is about twice as high as the price of a similar stand-alone PV system due, in part, to the higher non-hardware costs of storage. Specifically, we found that hardware costs constitute about half the total price of a small-battery system and about 60% of a large-battery system, while the remaining costs comprise non-hardware items (such as net profit, sales and marketing, interconnection, or installation labor).
As noted earlier, energy storage deployment has been impeded by both cost and value barriers.
In our interviews with 22 representatives from 18 leading organizations closely involved with PV+storage research, product development and installation, we found that permitting and interconnection ranked among the most significant of the non-hardware cost barriers to PV+storage deployment. Obtaining permission to install and operate a residential energy storage device can be a complicated, expensive and uncertain process, with many jurisdictions and utilities requiring more documentation and inspections than typically required for stand-alone PV systems. Our benchmarking results suggest that permitting, inspection and interconnection (PII) costs for storage add between $700 and $1,200 to the installed price of a stand-alone PV system, depending on the configuration. However, modeled PII costs, based on installed systems, do not sufficiently capture the costs of regulatory delay or inconsistent permitting and interconnection requirements.
Permitting and interconnection timelines and costs also reflect a lack of local familiarity with storage systems. Several industry stakeholders reported the need to work very closely with permitting officials and utilities throughout each step of the approval process to ensure that they addressed all concerns and questions raised. The unfamiliarity with storage and lack of standardized permitting and interconnection processes introduce additional regulatory uncertainty and can slow PV+storage growth.
In general, many of the benefits offered by PV+storage systems, especially those offered to the grid, are often undervalued. Distributed energy storage could be used to provide a number of grid-level benefits, such as voltage and frequency regulation, deferred infrastructure investment, and resource adequacy. New business models that aggregate and coordinate a fleet of networked residential PV+storage assets could provide these grid-level benefits. However, current market and regulatory constraints make it difficult to realize these value streams. To the extent that these additional value streams could improve the economics of residential-scale PV+storage, the undervaluation of energy storage at the grid level poses a barrier to PV+storage deployment.
In U.S. deregulated electricity markets, generation, capacity and ancillary services are bought and sold on wholesale markets, whereas transmission and distribution services are generally rate-based. Energy storage can technically provide several of these services, but current regulatory structures typically require prospective storage aggregators and/or utilities to make a mutually exclusive choice between selling into wholesale markets or rate-basing energy storage investments to provide transmission services. This structure prevents prospective aggregators from realizing the full potential value of aggregated energy storage devices – and passing this value onto residential customers.
Several recent Federal Energy Regulatory Commission (FERC) orders have begun to lay a framework for improved storage valuation by allowing non-generation resources to provide ancillary services and increasing payments to fast-responding resources – including batteries – that bid into frequency-regulation markets. In November 2016, FERC proposed an additional rule that would require regional transmission organizations and independent system operators to create regulations that accommodate the “physical and operational characteristics” of energy storage devices. These developments could ultimately allow residential customers to realize additional value streams from their PV+storage systems. This would improve the overall economics for individual systems, spurring further deployment.
Finally, flat electricity rates prevent PV+storage systems from providing value through load shifting because there is no incentive to shift excess PV generation from one time of day to another. This loss of value is most notable when net metering is available. Many of those interviewed for the report believe that properly designed, mandatory residential time-of-use rates could improve the load-shifting value proposition for PV+storage systems.
Taken together, these factors have resulted in significant regulatory uncertainty – frequently cited among the primary barriers to increasing deployment – higher soft costs, and unrealized or under-realized value for PV+storage.
Low-cost, customer-side energy storage products have the potential to optimize the value of rooftop PV while increasing the flexibility of electricity consumers and enhancing grid operations. Yet today, deployment of storage systems in the U.S. residential sector is lagging behind deployment in the commercial, industrial and utility-scale sectors. Of the total 226 MW of energy storage deployed in 2015, less than 35 MW was behind the meter, and only about 4 MW was residential.
However, analysts believe this ratio will change, estimating that 49% of total annual storage installations by 2021 will be behind the meter, including 463 MW in the residential sector. Further, the percentage of residential PV systems coupled with storage is projected to grow from 0.11% in 2014 to 3% in 2018.
Our report is the first in a planned series of studies to benchmark the evolving costs of residential PV+storage, and moving forward, we will further refine our cost model and include an even more comprehensive approach. Our long-term objective is to understand how distributed energy storage innovations – both in electrical battery storage and other forms – can interact with and enhance PV value.
Kristen Ardani is senior solar technology markets and policy analyst at the National Renewable Energy Laboratory. This article is adapted from a new NREL report co-authored by Ardani.
