Feature

Are residential demand charges the best rate reform for DERs?

The debate over rooftop solar is shifting in a new direction, with utilities and regulators examining new rate reform methods

Talk about rate design reform is picking up again this year as utilities and regulators search for new ways to precisely charge residents for their energy usage, curtail peak load and properly compensate distributed energy resources.

At the last meeting of the National Association of Regulatory Public Utility Commissioners (NARUC) in 2015, officials from the electricity industry and states indicated a desire to move beyond fixed charge increases — which many utilities proposed to regulators in order to better recover fixed costs amid rising DER penetration — to more sophisticated rate design at the residential level. 

Now, some utilities are turning to residential demand charges as a new rate reform tool that could help them manage DER growth. But demand charges have come under fire for a number of reasons, including being too complex for everyday consumers to understand.

The discussion surrounding demand charges came into focus at NARUC’s winter meeting last month. A panel of analysts from organizations such as Rocky Mountain Institute and Advanced Energy Economy discussed how utilities could implement residential demand charges and distill their complexity for consumers, while moving forward in their goal to manage the increasing proliferation of DERs on the grid.

Wanted: Tech-agnostic rate reforms

With the proliferation of DERs, the panelists at NARUC advocated for “technologically agnostic” or neutral ways to deploy all these emerging technologies into the grid.

Some utilities have argued that residential demand charges fit that description well. Traditionally applied to commercial and industrial customers, demand charges calculate a fee for utility customers based on their peak consumption each month, usually measured hourly.

In many cases, these demand charges account for a substantial portion of a customer’s bill, creating a significant incentive for the consumer to reduce peak usage. Customers can do that through a variety of actions — from leveraging solar panels to generate during peak hours to deploying storage to store energy for peak demand periods and utilizing home energy management tools to track and reduce usage.

Solar advocates commonly oppose the imposition of demand charges, pointing to claims from leading solar developer SolarCity that new rooftop solar applications fell 96% in the service area of Salt River Project, an Arizona municipal utility, after it added $50 in monthly fees for solar users, primarily through demand charges.

But analysts say that while the value proposition of rooftop solar can be altered or hurt by demand charges, they also open up opportunities for other technologies, particularly energy storage. Last year, GTM Research analyst Ravi Manghani told Utility Dive that even if all the incentives for storage in the state of California were to disappear tomorrow, the technology would still be appealing to customers solely through its ability to cut demand charges.

“Even without these incentives, among specific customer types, storage could make sense,” he said. “We’re looking at specifically demand charge reduction as the key end customer use case that storage is economical for.”

“Any kind of net energy metering reform that reduces the value of solar works in favor of storage,” he added.

But utilities looking to institute residential demand charges also “risk alienating customers,” according to Lena Hansen, managing director at the Rocky Mountain Institute.

“They are not understandable. While they serve for cost recovery purposes, they don’t serve for...driving customer behavior," she said. “Another important thing about rate design [is that] making many changes in the sector are often not wise ...changes [need to be] made in a slow and consistent way so that people understand it."

How to make those changes is a challenge, Hansen and the other panelists acknowledged. They advocated against targeting a specific technology like rooftop solar.

“There’s a danger to making rates too technological,” Hansen said during the panel. “It’s not just about solar but integrating [all technologies] and finding a way to send price signals reflecting cost-of-usage.”

The debate over demand charges in Arizona

Already a hotspot for utility-solar debates, the state of Arizona is poised to heat up again this year as two utilities already have or are seeking to implement residential demand charges on rooftop solar customers.

The board of Arizona’s major public utility — Salt River Project’s — approved a 3.9% increase in customer rates and approximately $50 in distribution and residential demand charges for solar only last year.

SolarCity, the market-leading residential solar company, has filed a lawsuit saying the new rate plan discriminates against rooftop solar users. The lawsuit is ongoing. The developer claimed the fees have reduced new applications for distributed solar in SRP’s territory by about 96% last year.

Now another rural Arizona utility is seeking to make a similar move this year. UniSource Energy Services (UES), which serves 93,000 customers, asked the Arizona Corporation Commission (ACC) last month for approval on a mandatory demand charge for new solar owners and an optional demand charge for all other customers.

Some members on the ACC staff wants to make the demand charges mandatory for all UES customers, not just rooftop solar, which could set a precedent for other regulated utilities in the state, according to the Arizona Republic.

The stakes are higher this time around because UES falls under ACC’s purview as a regulated utility whereas SRP, as a public utility, does not. Subsequently, SRP's decision had little direct impact on the other utilities in the state. Now, the big utilities in the state, Arizona Public Service and Tuscon Electric Power, have joined the UES case alongside solar lobbying group The Alliance for Solar Choice.

Residential demand charges are gaining traction in states like Arizona since they could be applied equally, with utilities saying they are preferable at collecting fixed costs without singling out a specific technology versus time of use pricing.

This line of thinking was underscored by a Navigant Consulting study commissioned by APS to examine third-party owned solar financing, the business model of major solar developers such as SolarCity and Sunrun. Part of the study reviewed how developers reliant upon TPO financing still had headroom to adjust to rate changes, which could include demand charges.

Demand charges will "allow customers opportunities to save on their bills,” said Greg Bernosky, APS’s director of state regulation and compliance. “Especially for solar customers, there are emerging technologies that allow keeping an eye on peak demand to get to those savings. We have seen a lot of customers save when they move to a demand rate.”

But solar developers are skeptical of the study’s findings. Will Craven, spokesman for SolarCity, told Utility Dive in an email that they are “simply not grounded in reality.”

“We can only assume that they are based on ridiculous assumptions,” he added.

Expect Arizona to once again be a hotspot this year, with regulators, utilities and solar advocates all debating the best rate design to compensate DERs while allowing for utilities to recover their fixed costs.

Looking ahead

There’s more going on in the rate design world this year beyond residential demand charges. The momentum for residential demand charges appears to be springing off of the wider acceptance and familiarity of time-of-use pricing, another variable rate design option

TOU pricing, like residential demand charges, has evolved into a popular option for rate design, long considered by industry experts as a more elegant way to set price signals aligning with peak demand that will curtail customer’s usage during those hours. 

Demand charges and TOU rates are frequently paired together to incentivize customers to reduce their energy usage, or pay higher rates, during peak load times. Both set the stage for rate arbitrage, where DER owners can take advantage of peak demand to export their excess energy to the grid while cutting down on their own bills. Solar could benefit so long as peak production aligns with a utility’s highest rates.

Hawaii is one state weighing both residential demand charges and TOU pricing. 

Hawaii recently revised net metering policies that attempt to strike a balance between utilities’ need to recover fixed costs and distributed solar advocates’ push for proper compensation for the excess energy sent to the grid. Now, the state is also looking at reforming rates in the face of increasing penetration of DERs. An ongoing docket, opened in 2014, calls for new time-of-use pricing as DERs and other new technologies expand.

Hawaii PUC Commissioner Lorraine Akiba told Utility Dive at the NARUC winter meeting that the rate reform options should be palatable to both sides, especially when addressing the future expansion of new technologies. She wouldn’t comment directly on the ongoing docket, but said the decision to replace the net metering program reflects the Commission’s push to ensure customers are properly compensated for energy consumed through, or sent to, the grid.

How the debate over residential demand charges will play out remains to be seen as the Hawaii and Arizona cases proceed throught the year. But as these solar markets are more advanced than others, how these states choose to compensate DERs could set a precedent for other states across the country.

Follow on Twitter

Filed Under: Solar & Renewables Regulation & Policy
Top image credit: SDG&E