Utilities have long seen the potential value in distributed resources — not just to support the power grid, but their bottom lines as well.

In last year's State of the Electric Utility survey, 56% of utility sector respondents said they saw opportunity in DERs, but were unsure about how to build business models around them. 

Fast-forward one year, and the sector appears to be in the early stages of figuring out some solutions.

In this year's Utility Dive survey, 60% of utility professionals surveyed said their utilities should partner with third party vendors to deploy DERs. 

But the survey didn't limit respondents to choosing just one DER business strategy, and many respondents chose multiple options. Nearly the same amount (59%) said they thought their utility should own and operate DERs, rate-basing their investments in the technologies. 

These two seemingly contradictory strategies being explored by utilities suggests they “are still weighing a variety of options for DER-centric business models and may even be pursuing multiple opportunities at the same time,” the survey reports.

Looking deeper does not resolve the contradiction: 39% of those surveyed said the business model could be built on “procuring or aggregating power from DERs owned by third party providers.” That means ownership is retained outside the utility.

But 29% said owning and operating DERs through an unregulated subsidiary is another possible way to go. The unregulated utility would compete with third party vendors and the DER investment would not come from the rate base, but it is still utility ownership instead of ownership by third parties.

Utility ownership of DERs

As utilities across the nation move toward a less centralized power system, many of them are learning about how to operate and deploy distributed resources through rate-based pilots, which may help explain the popularity of the utility ownership option for DERs. 

Xcel Energy, for instance, recently asked Minnesota regulators to allow cost recovery for a solar-plus-storage pilot intended to answer the question of whether utility ownership or third party ownership works better for them. It could be “the first entry in the next marketplace, like wind was a decade ago,” Regional VP Aakash Chandarana told Utility Dive.

Xcel wants to spend $12.5 million of customers’ money instead of the $6 million it would have spent on a traditional substation upgrade because “the long term benefits of learning from this pilot would outweigh the slightly higher cost,” Chandarana said.

Similarly, The Avista Utilities are already moving toward ownership of DERs. Grants support the Pacific Northwest electricity and natural gas provider’s early pilots but the investor-owned utility’s rate base will also provide funds.

“We in the utility industry haven’t been able to value those things that are closer to the customer and the services that get delivered on the distribution system,” said Electrical Engineering Fellow Curt Kirkeby. “All our values are up in the bulk power system and come from the retail rate we charge.”

DERs have already enabled Avista to defer investment in a new natural gas peaker plant. “It was originally planned for 2020 and now is planned for 2022 or after,” Kirkeby said.

Avista is implementing a deployment of DERs and taking on the challenge of understanding the value streams at the distribution level for both the customer and the utility, Kirkeby said.

The Avista and Xcel initiatives mirror similar utility-owned DER projects underway from sector counterparts like Arizona Public Service and utilities in New York and California. And whether they are pilot projects or not, utility respondents to the survey seem keen to find more ways to own and operate distributed resources themselves: 65% said regulated utilities “should be able to own and rate-base DER investments in all or most circumstances.”

Another 17% said utilities should at least be granted cost recovery “in specific instances where the competitive market fails to deploy DERs that would benefit the grid.”  

The concept of limiting utility DER ownership to situations where third parties fail to deliver was pioneered by the Reforming the Energy Vision regulatory initiative in New York, which aims to transform the state's regulated utilities into distribution system platform providers who facilitate the deployment and interconnection of DERs from various entities on the grid.

But even in that state, regulators have approved utility-owned DER pilot projects at the behest of DER companies, who worry the regulated entities will try to edge further into the market later.

But already the fruits of early utility DER investment are showing fruit. Advocates say the landmark Brooklyn Queen Demand Management Program shows how this kind of investment can lead to ratepayer savings and grid benefits. Spurred by REV, Consolidated Edison used a $250 million investment in DERs to defer a $1 billion substation upgrade.

Third party partnerships

In Minnesota, distributed energy interests were not pleased with Xcel's plan to rate-base its pending DER project. As in New York, the advocates raised concerns that the utility would continue to pursue rate-based DER investments even after their pilot project was deployed. 

While the Energy Freedom Coalition of America — a group of renewable energy and DER advocates led by SolarCity — had supported Xcel's intent to expand DER use throughout the regulatory proceeding, the group's final filing recommended that Minnesota regulators reject Xcel’s project. Instead of rate-basing the investment, the group argued, Xcel should open the process up to open bidding from third parties. 

“Innovation can be more rapid and diverse in a competitive market,” EFCA argued. “The proposed project—which includes utility ownership of each component—will likely be more cost-effective and beneficial if it leverages the competitive market.”

A competitive bidding process “could result in a broader set of options, including technologies and ownership models, beyond the limited scenarios Xcel considered,” it added.

A recent white paper from SolarCity supported that argument that third-party partnerships for DER deployment could result in lower-cost solutions than utilities going it alonge.

DERs “can offer deferral and avoidance of planned grid investments…[and] if deployed effectively and placed on equal footing in the planning process with traditional grid investments, can ultimately lead to increased net benefits for ratepayers," the paper notes. But reducing a utility’s infrastructure investments “cuts directly into shareholder profits." DER investment could therefore “adversely impact shareholder earnings.”

This institutionalized barrier to utility deployment of DERs could help explain why many survey respondents are interested in exploring partnerships with third party providers for DER deployment.

The SolarCity paper proposes a solution: Infrastructure as a Service (IAS) to allow utility-vendor partnerships and eliminate the financial disincentive to utilities.

Today, if a utility spends $20 million upgrading a substation, its guaranteed 10% return would produce a $2 million profit, the paper posits in a hypothetical case. DERs deployed by third party vendors might defer or eliminate that upgrade at a $15 million cost. It would benefit ratepayers but not the utility and its shareholders.

If regulators allow the same $2 million return for a $15 million contract with a DER provider, the total assessment to ratepayers is $17 million instead of $22 million. The utility and its shareholders earn the same profit. But ratepayers save $5 million.

“IAS makes the utility indifferent so it can make the right choice for its ratepayers," SolarCity Grid Engineering Solutions Sr. Director Ryan Hanley said.

Reforming rates for DERs

As utility leaders mull how to enter the DER market themselves, they are also considering how to respond to the steady proliferation of distributed resources already taking place throughout much of the nation. 

As consumers increasingly generate and store their own electricity, they pay less to the utility, decreasing its revenues. The problem is accentuated by the fact that 74% of utility executives’ expect minimum or stagnant load growth in their territories and another 9% expect declining load growth. Only 18% expect the load in their territories to increase.

“While the sheer volume of electricity sales lost to DERs in most regions of the nation is still small, stagnant or declining load growth can make even small increases in DER penetration significant for utility earnings,” the Utility Dive survey reports.

In response, utilities across the nation are moving to change their rate structures so they can better recover costs from customers who install DERs like rooftop solar or residential storage. 

To date, the most popular solution has been to increase fixed charges on customers. In 2015. 61 utilities in 30 states proposed fixed charge increases, according to a report from NC Clean Energy Technology Center. Those moves have drawn ire from solar advocates, who have said the requests would damage the growing distributed solar sector.

The drive to adjust rate design for DERs was reflected in this year's survey. When asked the best way to deal with decreases in revenue as a result of DER load defection, 38% chose reforming rate structures.

But over half of Utility Dive's respondents have different ideas. More than a quarter (27%) said the answer is offering renewables options like green pricing and community solar. Another 26% would like regulators to change the traditional utility revenue model to eliminate financial disincentives for DER investment. Only 6% say the best idea is lower remuneration for distributed generation (DG) and only 3% want to cap the DG utilities can interconnect.

Even the rate reforms proposed by respondents suggest utility leaders are thinking about more about how to accelerate DER deployment while protecting their bottom lines. Over half of respondents (55%) said time-of-use (TOU) rates that price electricity higher during periods of peak demand are the best response to DER growth.

Another 29% favor increased fixed charges to residential customers, 28% favor increased demand charges, 21% suggest increased demand charges only to DER-owning customers, and 20% suggest increased fixed charges to DER customers.

Most of those latter reforms would effectively impede the DER value proposition and slow progress, according to a recent study by GTM Research. And when proposed, such rate reforms have been met by much opposition. Utilities have not often been able to get regulators to impose them, study lead author Cory Honeyman recently told Utility Dive. “Utilities should consider putting forward more sophisticated proposals instead of blunt instrument fixed charges.”

A better goal might be, Honeyman suggested, “rate structures with price signals that drive DER owners to deliver power at periods of peak electricity demand so they become grid assets.” 

The 2016 survey suggests that a growing number of utility professionals are beginning to agree with him. Despite the popularity of fixed charge increases in recent years, TOU rates beat them out in the survey, and demand charges proved popular as well. But as the survey indicates, the divisions suggest that “utility executives do not believe there is a silver bullet for rate design in response to growing levels of DERs."

The findings also point to a trend toward “a more diverse approach, such as pairing small fixed charge increases with TOU rates and residential demand charges,” the survey concludes. “All of these approaches are intended to reorient rate structures to account for the new realities of electric service in 2016.”

Looking ahead