It turns out that utilities aren't just being paranoid. Solar power really is out to get them.

According to a new report from researchers at the Lawrence Berkeley National Lab, utilities and their shareholders could see substantial declines in revenues as solar penetrations increase -- assuming they don't seize the solar opportunity themselves.

The study modeled two prototypical power companies, one a vertically integrated utility in the Southwest U.S., the other a wires-only utility in the Northeast that uses power purchased from third-party generators. The former could be compared to Arizona Public Service, and the latter is analogous to National Grid.

Unlike the many studies that compare the costs and benefits of solar for customers and utilities, the study focused exclusively on calculating the revenue and rate impacts of distributed PV.

The study included a number of scenarios wherein distributed solar ramped up to between 2.5 percent and 10 percent over ten years. Only Hawaii has a penetration level higher than 2.5 percent. 

At the lowest level, the study found that distributed PV resulted in about a 4 percent reduction in shareholder earnings for each of the two utilities. In the highest scenario of 10 percent penetration in ten years, shareholder earnings might be reduced by anywhere from 5 percent to 13 percent for the Southwestern utility and by 6 percent to 41 percent for the Northeastern utility, depending on a host of assumptions and options.

Solar cuts into utility revenues in two ways, the authors say. First, it reduces utility power sales more than it reduces costs, leading to a “revenue erosion effect.” Second, especially for regulated utilities, it reduces their need for future capital investments, thereby cutting future earnings from returns on equity.

The impacts on average retail electricity rates, however, were considerably smaller. There was virtually no rate increase in the lower-penetration solar scenarios, and rate increases only rose to about 2.5 percent in the highest PV penetration scenarios. This finding is an average across all customers, and does not measure cost-shifting between PV and non-PV customers or between any other customer classes.

A key variable in these results is an assumption about how valuable PV is to the power system as a whole. Regulators will have to assign a capacity value to solar and give a value to avoided transmission and distribution costs. While the actual dollar values in the study were very sensitive to the assumptions chosen, they did point in one interesting direction: assigning a high value for distributed PV results in lower ratepayer impacts, but higher shareholder impacts.

In other words, if solar is worth more for the grid, that’s good for consumers and bad for shareholders.

“This is not commonly appreciated,” said co-author Galen Barbose. “The more infrastructure PV defers, the worse off the infrastructure investors are.”

The study also tested other variables, which may reaffirm current regulator and utility fears. Decoupling utility profits from electricity sales, as California and other states have done, addresses short-term revenue impacts, but does not address the loss of future capital investments. 

Low load growth is bad for utility finances; combining that with solar is a double hit. In an extreme scenario for the Northeastern utility, shareholder losses were 41 percent due to a combination of low load growth and 10 percent PV penetration. “Energy-efficiency technologies have the same kind of impacts on revenues,” Barbose pointed out.

When regulators take years to adjust rates, that delay can increase losses. Barbose said this problem is especially acute now, in a time of rapid change.

Lastly, the study points out that when customers pay low fixed charges, the loss of electron sales from self-generation cuts into revenues -- the reason why the Edison Electric Institute and numerous utilities around the country are pushing to increase fixed charges.

So what can be done? 

The regulatory response to the growth of distributed solar will be where these issues are resolved. 

Regulators could make changes to utility rate design and ratemaking processes, adopt mechanisms that allow utilities to recoup revenues lost due to distributed PV, or let utilities earn profits on distributed PV, among other strategies.

“In many cases, they involve important tradeoffs -- either between utility ratepayers and shareholders or among competing policy objectives,” said Andrew Mills, a report co-author.

The researchers looked at a number of options for balancing the financial picture, such as increasing fixed charges for consumers, paying utilities for lost revenues, and giving performance-based incentives to shareholders. In short, these options mean putting more money in utility pockets by taking it out of consumer pockets.

Another option is to let utilities take the renewable energy credits (RECs) resulting from customer-owned PV, in order to count them against their RPS obligations. Not only might some consider this a “regulatory taking,” it would also lead to solar homeowners no longer being able to legally claim they are producing renewable power. The Federal Trade Commission has made it clear that if RECs are sold, the producer can no longer make claims that their power is renewable.

Perhaps the least onerous option, the authors suggest, is to let utilities invest in or finance distributed solar themselves, thereby earning back what they would otherwise be losing to customers.