In February 2014, researchers at Rocky Mountain Institute (RMI) released a report that outlines how rooftop photovoltaic (PV) arrays, combined with battery-based energy storage could lead electric-utility customers to opt out of the connected grid. Now, a follow-up RMI report suggests that a more likely result of wider PV/battery adoption is partial, rather than total, grid defection. While this might sound like better news for utility managers, it turns out that losing some of a customer’s business could pose even greater challenges to electric-utility business models than losing all of it.


In “The Economics of Load Defection,” released in April, researchers describe how increasingly affordable PV panels and lithium-ion batteries could lead to on-site production and storage becoming a customer’s primary electricity source, with grid power as a supplement and security blanket, ensuring lights stay on if on-site equipment goes down. Such a system wouldn’t have to be as robust as a design intended for independent operation, making it a significantly more affordable alternative for today’s utility ratepayers.


With last year’s report, “defection was something that might happen, and the economics were something that might happen,” said Leia Guccione, an RMI manager and one of the report’s 13 co-authors. 


However, a grid-connected, optimally sized PV/battery system designed to supply most, if not all, of a home or business’ demand provides the more attractive advantages of both lower electricity costs and the security of a backup-grid connection.


“It’s much more likely that customers will invest in these systems than cut the cord entirely,” Guccione said.


To reach their conclusions, researchers used the HOMER software package, originally developed at the U.S. Department of Energy’s National Renewable Energy Laboratory to model electricity rates and customer-sited system costs from the present day through 2050 in five locations: Honolulu; Los Angeles County; Louisville, Ky.; San Antonio; and Westchester County, N.Y. The researchers considered a generic 43,000-square-foot, four-story hotel for commercial loads and a 2,500-square-foot detached, single-family home to model residential use patterns. The results are conservative; neither residential nor commercial calculations included any allowance for the net-­metering benefits now driving PV adoption in many states. Three system configurations were tracked: grid power only, grid plus solar, and grid plus solar and battery.


The stand-out finding: “Distributed solar first, and then solar-plus-battery systems covering only a portion of a customer’s load will have compelling economics without the support of incentives or feed-in compensation in many important markets within 15 years.”


This report comes at a significant moment in the history of the U.S. electricity industry. Utilities and independent power producers are scheduling closures for a large number of aging coal generating plants across the country, and planners are doing a bit of scrambling to determine the best way to meet demand (which remains stagnant, even as the economy improves). The data from this report would indicate that simple like-for-like replacement of plants scheduled for shutdown could be a shortsighted approach, leaving ratepayers and independent power-plant owners stuck paying for generation capacity that might not be needed in another 15–20 years.


Companies that own generating plants are most at-risk in the scenarios outlined by RMI’s researchers because the value of energy will decline, as centrally produced power is forced to compete on price with electricity produced and stored by customer-sited systems, Guccione said. This could mean big challenges for vertically integrated utilities (i.e., those that own their own generating plants) as well as owners of independent power plants that sell electricity by bidding it into an open market. However, there could be a big upside for the local distribution companies responsible for the grid connection and possible new service offerings.


A major roadblock remains in the way of the hybrid systems envisioned by RMI. The report assumes behind-the-meter systems capable of directly serving customer-side loads. The Institute of Electrical and Electronics Engineers’ (IEEE) Standard 1547, which governs how distributed energy resources (such as PV panels and on-site batteries) connect to electric-utility grids, denies such designs because of a risk of electricity feeding back into the grid during an outage, putting electrical workers in danger. The working group behind IEEE 1547 could be investigating how new technologies, such as smart inverters, could address such concerns.


Guccione and co-author Bodhi Rader, an RMI senior associate, emphasized that their primary goal with this new report was not to advocate for any particular system design but to call attention to the possible implications of rapidly shifting economics in the electricity marketplace. With PV/battery systems soon making sense without added incentives, spending money on expensive central generation may be making less sense over the next several decades.


“One of the messages we tried to get across is, you need to really think about those long-term assets a little bit more to be sure those assets make sense,” Rader said. “There’s time now to really rethink the investments you want to make.”