Forget the threat of solar- and battery-equipped customers defecting from the grid. The real threat for utilities unwilling to adapt to grid-connected customers installing ever-cheaper solar and energy storage technologies is “load defection” -- and that future will come whether or not utilities and regulators support it with net metering regimes and customer-grid integration, or try to fight it with fixed customer charges and other roadblocks.

These are some of the top-line findings from “The Economics of Load Defection” report released Tuesday by the Rocky Mountain Institute, CohnReznick and Homer Energy. Calculating the economics through 2050 for median commercial and residential customers in five U.S. markets, the report shows that grid-connected solar-storage systems are already more cost-effective than grid-supplied electricity in expensive electricity markets like Hawaii, and will be more economic than grid power in three of five U.S. geographies studied, including California, New York and Texas, within the next 10 to 15 years.

That, in turn, could lead to more and more customers shifting their energy load from utility-delivered electricity to their own self-generated and stored power -- thus, the term "load defection."

Tuesday’s report is the long-awaited sequel to the “Economics of Grid Defection” report released last year, and it looks at the same five cities modeled in the previous report: Honolulu, Hawaii; Los Angeles, California; Louisville, Kentucky; San Antonio, Texas; and Westchester, New York.

Using Homer Energy’s modeling software and U.S. Energy Information Administration data, the new report modeled grid only, grid-plus-solar, and grid-plus-solar-plus-battery configurations to find the lowest-cost options over time, based on systems’ per-kilowatt-hour levelized cost of energy equivalents.

But unlike the "Grid Defection" report, which projected when solar-plus-storage systems will become cheap enough to convince large numbers of customers to disconnect from the grid, the new report analyzes at what speed these technologies will start to become economically attractive enough to start significantly eroding the profits that utilities make by selling electricity to their customers.

Because grid-connected customers don't need to buy nearly as much PV and battery storage to provide their full electricity needs, the load defection scenarios will proceed more rapidly than the grid defection ones, the new report finds. While these customers will still be buying utility power, they’ll be buying less and less of it as time goes by.

That will equate to “substantial utility load loss well within the economic life and cost recovery period for major assets” like central, fossil-fuel-fired power plants and transmission and distribution grid infrastructure, the report states. For example, by 2030, Northeast U.S. energy sales could be cut in half for residential customers and cut by 60 percent for commercial customers, adding up to a combined $34.8 billion in lost utility revenues.

That’s a problem for a U.S. utility sector that will require about $2 trillion in grid investments between 2010 and 2030, or about $100 billion per year, mostly paid for through revenues from energy sales. To make up for this potential loss, utilities face two different choices today, the report states -- to work with regulators and customers to share the costs and benefits these distributed energy resources can deliver, or to fight their spread through legislation or regulation that limits customers’ ability to adopt them.

Why cutting net metering and imposing fixed charges won’t stop load defection

Unfortunately, RMI’s analysis doesn’t paint a rosy picture for utilities that try to stem this trend. Notably, its analysis took a conservative stance and didn’t include the economic effects of any “export compensation.” These include the net metering regimes in 43 states that allow small customer-owned PV systems to earn money for the power they put back onto the grid, as well as feed-in tariffs, avoided fuel cost compensations, or other means of paying customers for self-generated power they don’t consume themselves.

That means that “eliminating net metering is not going to prevent load loss,” Leia Guccione, a manager at RMI’s electricity and industry practice and co-author of the new report, said in an interview. “The decline in purchases from the grid, while it may be delayed, still happens. Eliminating net metering will only buy you time.”

Likewise, the fixed charges that utilities across the country are imposing on solar-equipped customers “might disincentivize customers from trying to install a grid-connected solar battery system” in the short term, she said. But as financial analysts such as Morgan Stanley have pointed out, “in the long run, it’s just going to push people toward grid defection -- which is also not optimal,” she said.

Today’s battery-backed solar deployments are cost-effective largely through federal and state incentives, as GTM Research points out in its projections of a $1 billion U.S. market for solar-storage systems by 2018. But in the long run, the continuing reduction in costs of solar PV systems and the falling price of lithium-ion batteries could well surpass the impact of incentives on these economics.

Meanwhile, the solar-battery connections are being forged by most of the country's largest solar manufacturers, project developers and third-party residential and commercial installers, including SunPower, SunEdison, SolarCity, NRG Home Solar, Sunrun, Vivint Solar, Kyocera and Sharp.  Behind-the-meter battery installers and aggregators such as Stem, Green Charge Networks, Coda Energy, Sunverge and (reportedly) Tesla, are similarly building their connections to rooftop solar.

Finding the win-win path to avoid grid-customer disconnection

But before this scenario has a chance to play out, utilities and regulators will need to find a way to align their economic imperatives. RMI’s report calls the choices before them following two possible paths in a “metaphorical fork in the road,” which will lead either to a future in which customer-owned energy resources and grid systems can work in an integrated fashion, or one in which both utilities and customers end up overinvesting in redundant systems.

Whether it’s grid defection or departing load that’s at stake, “the commonality between the two reports is that both of them are showing the urgency with which we need to start transforming utility business models,” Guccione said. “We need new utility business models that are not so dependent on capital investment and getting returns on capital investments. We need to think about business models where utilities are acting more as integrator and coordinator, not just as asset owner.”

Tuesday’s report lays out multiple reasons “beyond simple economic parity to invest in solar-plus-battery systems, including decreased carbon intensity, improved resilience, mitigated or avoided impact of future potential rate increases, ancillary services provision (e.g., frequency and voltage regulation), deferral of distribution system upgrades, reduction in peak power usage, and power quality management.”

New York’s Reforming the Energy Vision (REV) proceeding is a good example of the kinds of broad-reaching reforms that will be needed to make this transformation possible, Guccione said. Of course, “we all know that regulatory reform [and] rate reform do not happen quickly, and that new utility business models don’t emerge overnight.”

Still, if there’s one key message for utilities and energy regulators to take away from these analyses, it’s that “there is a real cost to doing nothing,” she said. “In the absence of more customer choices, customers will take matters into their own hands. And that’s going to lead to sub-optimal outcomes that we see in grid defection -- overinvestment and underutilized capital,” for customers and utilities alike.