Coming soon to affordable housing: Solar-plus-storage?
A new report finds combining solar and storage at affordable housing projects can pay for itself if the conditions are right
When it comes to the cutting edge of solar power, solar-plus-storage is at the forefront.
Like solar power itself, the target market tends to skew toward the middle class, if not the well heeled, but a new report from the Clean Energy Group of Montpelier, Vt., turns that idea on its head.
The report makes the case that, with the right incentives, solar+storage systems can offer an economic return and provide much-needed resiliency to affordable housing projects.
Distributed technologies 'can make economic sense for building owners to install now'
The report, part of a series issued through the Resilient Power Project, a joint venture of the Clean Energy Group (CEG) and Meridian Institute, presents the findings of case studies in three cities: Chicago, New York, and the District of Columbia.
“This analysis shows us something we didn’t expect, these new resilient power technologies can make economic sense for building owners to install now, not years from now,” said Lewis Milford, a co-author of the report, president of CEG and non-resident senior fellow at the Brookings Institution.
The aim of the project is to expand the use of clean, distributed generation to avoid power outages among vulnerable populations and at critical facilities in order to reduce the impact of severe weather events such as Superstorm Sandy, which hit states along the Eastern Seaboard in October 2012.
In the report, the Clean Energy Group examined scenarios in which solar+storage is installed to serve the common areas of affordable housing buildings with 100 to 300 units.
The report found that solar+storage can reduce operating costs in the cities studied, particularly in areas where utility demand charges are high. The report also argues that the payback period for solar+storage can be as short as a few years and that resilient systems can be installed at no net cost over the lifetime of a project.
Model cities for frequency regulation: Chicago and Washington
In Chicago, CEG modeled an affordable housing project with a 200-kW solar system and a 100-kW/50kWh lithium-ion battery and with the same solar array and a 300-kW/150kWh Li-ion battery.
The authors note that Chicago is not an ideal location for a solar+storage installation. Both power prices and solar insolation in the region are low, but Chicago draws its power from the PJM Interconnection, which has a market for frequency regulation services, which can be provided from batteries, and the city is also able to sell solar renewable energy credits (SRECs) in the Pennsylvania market.
Taking those factors into consideration, CEG estimates that the smaller solar+storage installation would have a payback period of 11.8 years and the larger system would have a 6.2 year payback period.
The case study for Washington, D.C., looked at a solar-only option, sized at 360 kW, and at the same solar array with a 100-kW/50-kWh Li-ion battery and found the same 3.5-year payback period for both systems.
The difference between Washington and Chicago is that the capital has an aggressive solar mandate that has driven SREC prices to historically high levels of nearly $500/MWh.
For the purposes of the study, the authors assumed that those SREC prices will hold up for the first five years of the project and then drop by 50% through year 15 and then disappear completely.
Washington, like Chicago, is within the PJM footprint and can participate in the frequency regulation market.
Peak shaving makes sense in New York
In New York City — where Hurricane Sandy left tens of thousands of public housing residents without power for elevators, water and communications — the CEG case study found quite a different scenario.
The constrained size of New York City roofs limited solar installations to 30 kW. And while New York, through the New York State Energy Research Development Authority, supports stand-alone solar installations, the state does not have a mechanism to support distributed energy storage. In addition, the New York ISO, which runs the state’s grid, has a 1-MW minimum threshold for participation in its frequency regulation market.
However, savings from peak shaving are still available for solar+storage installations in New York. That strategy — storing energy during low-peak, low-cost daylight hours and discharging it during peak evening demand periods — can reduce utility demand charges that are based on periods of high use.
The authors note, however, that because savings from peak shaving are based on actual electricity usage, the potential savings vary by location and do not lend themselves to scaling, so increasing battery size may not lead to improved returns.
Another challenge is that current New York City regulations prohibit the use of Li-ion batteries. So, for the New York City case study, CEG combined a 30-kW/60-kWh lead-acid battery with a 30-kW solar array. In the resulting analysis, the solar-only array had a payback period of 4.3 years and the solar+storage installation had a payback of 14.2 years.
The authors argue that policy changes in states like New York could provide incentives that could encourage private market participation in solar+storage markets in low-income areas, enabling “a market driven approach to resilient power projects in low-income neighborhoods.”
The fact that much of the economic benefit of solar+storage in the New York case came from peak shaving raises the question of whether solar+storage systems such as those studied by CEG have the potential to disrupt utility revenue models.
But, as Seth Mullendore, a project manager at CEG and one of the co-authors of the report, noted, developers installing those systems would likely decide from the outset how they would achieve their economic goals.
In the New York case study, CEG sized the batteries for peak shaving, while in the Chicago and Washington cases the batteries were optimized for frequency regulation. Technically, the same battery system could be used for either purpose, but it would not be optimal, Mullendore says. He also does not see a major threat to utility revenues if affordable housing developers embrace solar+storage. Among other things, the systems are serving only the common areas of affordable housing units, so they do not represent a large share of utility demand.
The main point of the study, he says, was to show that by combining economic incentives and attributes, developers and owners of affordable housing projects can essentially provide residents with “resiliency for free.”
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