Beyond rate reforms: Bundling strategies could resolve net metering battles
An NREL study evaluated four common strategies used in these debates to find a solution for both sides
Debates over net metering policies nationwide are notoriously heated, with utilities and solar sector often sharply divided over how to compensate rooftop solar users for their excess energy.
Utilities say rooftop solar users don't pay their fair share to maintain the grid and shift those costs onto non-rooftop solar users. Solar advocates argue that utilities and regulators fail to quantify the full value and benefits of distributed solar. Rate reforms have been the primary tool of choice thus far in regulatory proceedings to settle the disputes.
But there could be a new way to resolve that debate and satisfy both sides beyond just rate reforms, according to a new report from the National Renewable Energy Laboratory.
“Rate reform and net metering reform have been the focus of efforts so far to address concerns about revenue erosion or cost shifting from (distributed photovotaices) DPV but that strategy is a zero sum game,” said Research Scientist Galen Barbose, a paper co-author. “You solve only the utility issues by eroding the economics of DPV and that is why it is so politically contentious.”
But there are ways “of addressing utility concerns that could win the support of the solar industry and create more opportunities for partnerships and collaboration between utilities and solar,” Barbose added.
The paper surveyed various forms of reforms, including rate design and efforts to deploy distributed solar in ways most useful for utilities, and place them in four categories, evaluating their strengths and weaknesses.
Four strategies utilities and solar advocates deploy
The most familiar strategy are requests from utilities to reduce net metering compensation, usually set at the retail rate, for rooftop solar customers. Net metering credits compensate rooftop solar users for the excess energy they send to the grid.
The second group of strategies are how distributed generation resources are deployed and utilized in ways valuable to utilities. Such strategies include finding locations and times when distributed generation is most valuable to the grid system.
Broadening customer access to solar through an expanded market is a third strategy. Popular methods to do so include programs designed to open up access to solar for low-income customers that don't necessarily qualify for loans or third-party financing. Utilities owning distributed generation or financing it would also also broaden access.
The fourth—and possibly the most complicated and forward-thinking—strategy, would be to align utility profits and earnings with the deployment of more distributed solar. Utility ownership and financing could also serve this purpose, as well as innovative rate structures like decoupling or performance based rates.
Some examples of these strategies can be seen in states with a high solar profile like Hawaii, California and Arizona. Take Hawaii: A rooftop solar market penetration tracking at more than 10% propelled state regulators to alter their net metering structure to alleviate impacts on other ratepayers. Other states are trying to stay ahead of rising market penetrations. Regulators in California, Nevada, Minnesota, New York and Arizona are introducing reforms that could have “profound implications for future DPV deployment,” NREL reports.
But in most utility territories, rooftop solar penetration “remains too low to produce significant impacts,” the paper adds. Finding a way to deal with the dilemma “is not urgent in most places but it must be dealt with,” Barbose said.
Reducing compensation to rooftop solar customers
This category contains enacted and proposed reforms. The most obvious is simply reducing the credit to customers for the electricity they export, which was part of the answer proposed in Hawaii and enacted in Nevada.
Other strategies seen in states included a fixed charge for distributed solar owners, a minimum bill and demand charge rates.
Utilities have pushed for these types of reforms in regulatory proceedings because they meet their main concerns about cost-shifts to non-rooftop solar customers, recouping lost revenues and preventing the resource from cutting into earnings opportunities from infrastructure investments.
In short, these reforms “address the concerns of both utility shareholders and non-solar customers and are often relatively straightforward to implement compared to more fundamental reforms to utility business models or markets,” NREL reports. But the main shortcoming is that these strategies comes from the "utility perspective only," adding to the political turmoil surrounding these debates, according to the report.
“They accomplish their objectives only by constricting DPV customer-economics and deployment…[and] could lead to substantial restrictions on future DPV growth,” according to NREL.
One possible exception to the “zero-sum” equation is community solar programs, the report notes. Well-planned larger arrays offer economies of scale that could reduce installed costs, which “may allow for compensation at prices below retail rates, while maintaining customer-economics comparable to rooftop DPV with full NEM.”
Some utilities, like Arizona Public Service Co. and Salt River Project, who are located in Arizona, have argued that the addition of customer-sited storage, smart devices, and load controllers could give customers the ability to protect themselves from changes to net metering with demand charges. But that would also “partially undermine the attempt to stem utility revenue erosion,” NREL notes.
Facilitate higher-value DPV deployment
Another strategy is deploying distributed generation systems on locations where utilities need it and structuring rates to reward output.
“Enhanced utility system planning can provide an analytical foundation for these pricing designs,” NREL reports. Eventually, such planning could lead to a more granular understanding of distribution systems and “higher-value DPV deployment through more finely targeted price signals or procurement processes.”
Time-varying, locational, and attribute-based rates, with price signals that obtain benefits, validate solar advocates’ arguments that there is more to DPV than a cost shift. They also create revenue streams to support DPV growth without raising concerns about unwarranted costs to other utility customers.
These value streams could allow utilities to protect shareholder and customer interests by reducing the net metering credit without undermining solar, the report said. Structuring such rates would begin with important work by utilities that California, New York, and Minnesota policymakers and regulators are already mandating.
This type of strategy addresses utility concerns about the cost shift burden and reduces lost utility revenues that would otherwise cut into shareholders’ returns on equity. But it does not prevent distributed generation from limiting utility earnings through infrastructure investments. In fact, deploying the strategy may promote the use of distributed generation to defer system upgrades and increase such lost investment opportunities.
But its biggest difficulty is that higher rates for attribute-based values impose short-term revenue impacts that are “immediate and unambiguously quantifiable,” NREL points out. That is against the “longer-term and less-readily observable nature of many system benefits.”
Broadening customer access to solar
Energy efficiency programs can also shift costs to customers who do not do upgrades, but have been “less susceptible” to the controversy surrounding net metering, NREL reports. The reason? They are“often supported by programs targeted to low-income or other hard-to-reach customer segments.”
But treating distributed solar in a similar fashion could address parts of the dispute over fair compensation between utilities and solar advocates by allievating a perception of fairness.
Broadening customer access for distributed solar would not specifically address the net metering cost shift. In fact, it would increase the cost shift by increasing the amount of net metered solar. But “cost-shifting and cross-subsidies have always been pervasive in retail rate designs, and those associated with DPV are, in the vast majority of cases, likely far smaller than many other sources of cost-shifting,” NREL notes.
Such concerns, it adds, “are often driven more by perceptions of fairness than by the mere existence or magnitude of a cost-shift.” Broadening access could accelerate reduced electricity sales and accompanying shareholder losses. And, like higher deployment strategies, it might promote the use of distributed generation. to defer system upgrades and in that way increase lost earnings opportunities.
Community solar may be “the most explicit path toward expanding customer access, if opportunities for participation are broadly available,” NREL reports. If the economies of scale it offers allow utilities to reduce the remuneration credit for exported electricity, community solar would be unique by meeting all three stakeholder concerns and covering all four strategy categories.
Both distributed solar and energy efficiency defer the need for utilities to make the capital investments on which they earn returns, which is a “pretty powerful disincentive for utilities to support growth,” Barbose said.
Utility-owned distributed solar, like the CPS Energy venture into rooftop solar, is one approach to mitigating the disincentive but has drawn fire from solar advocates. Solar industry vendors have argued that regulated utilities should not compete in an unregulated marketplace.
There are “different shapes and sizes” of utility ownership and some may be “more or less acceptable to utilities and to the solar industry,” Barbose said.
“If utilities have a piece of the action, it might mitigate their lost earnings opportunities,” Barbose said. “It would also allow them to help with where and how PV generation is offered, motivating them to help create higher value deployment. And it is a way to expand customer access.”
Take a pilot program proposed by APS, Barbose said. The program allows the utility to choose where rooftop solar will be located, to orient the arrays facing west to provide the greatest peak period benefit, and to install on roofs of an under-served lower-income customer segment.
This meets three of the four alternative strategies that would protect the value of solar, making only community solar a more complete solution.
There are many different potential utility ownership models that raise a wide range of unexplored questions about how shareholders, ratepayers, and solar industry stakeholders might benefit or not, Barbose said.
Align utility profits and earnings with distributed solar
Aligning utility profits and earnings with distributed solar is perhaps the most complex strategy explored in the report thus far, and doesn't address the cost-shift concerns. But innovative ways to restructure how utilities earn returns could help prevent lost revenues for utilities.
Regulators have already introduced “incremental” changes into utility business models, NREL reports. Decoupling, currently available in at least 22 states, separates electricity sales volume from returns, making utilities “immune” from rising distributed generation penetration.
Other alternative mechanisms reduce the lag-time from regulatory proceedings, allowing “timely” recovery of utilities’ costs through rates so they don’t have to wait years to recover money protected by decoupling in a new rate case, the paper added.
But the big change is emerging in the U.S. in the form of a transition from the traditional cost-of-service business model, NREL reports. The primary example of this shift is seen in New York's Reforming the Energy Vision intiative.
With performance based incentives and utility ownership or financing of distributed solar assets, utilities would be be rewarded for performance if it implements and manages distributed programs better than an established standard, NREL noted.
But the move doesn't directly address lost earnings opportunities resulting from the deferral of traditional capital investments; instead it reorients utility profits “around providing services instead of commodity sales of electricity,” the paper reports.
A path to peace
While no single category outlined in the report offers the proverbial silver bullet to peaceful resolution between utilities and solar advocates, there are common themes in all four that could be adapted to a solution, Barbose said.
This was the most suprising part, Barbose added. The researchers found each strategy addresses one or more of the concerns in a way that is a little more neutral toward distributed solar economics.
“There are ways of bundling them together that potentially address the full set of concerns,” he said. “We do not propose a specific bundle and it may not be possible to have a generic bundle. It would depend on the state’s specifics, its regulatory and market structure, its solar penetration, and other factors.”
Creating such a bundle specific to any given state would likely be challenging, as demonstrated ongoing work in places like New York and California, he added. “But people just beginning to think about these issues elsewhere might see this framework as a container for organizing different options.”