It’s no secret or surprise that the grid has become increasingly complicated over the past 10 years or so. If you had to explain why, distributed energy resources (DER) would likely top your list of reasons. 

According to a 2019 report from Navigant Research, global annual revenue from DER capacity will rise from $173 billion in 2019 to $650 billion in 2028, reflecting a compound annual growth rate of nearly 16 percent. Right now, 77 percent of utility respondents to Black & Veatch’s 2020 Strategic Directions: Smart Utilities Report survey say they have DER connected to their distribution systems that they neither own nor control. Still, they need to plan for those resources.

Joining the proliferation of DER as a grid-complicating factor are climate change, reliability concerns, aging infrastructure and regulatory pressures. All these forces are making utility managers band together like never before. They’re integrating planning efforts within the utility and increasingly incorporating third parties and customers into the resource mix through non-wires alternatives (NWAs) to traditional utility investments. Grid complexity has promoted greater collaboration inside and outside of a utility’s own hallways.

Coming clean

Utility managers have been wringing their hands about staffers working in silos for decades. Department A doesn’t know what Department B is doing, planning or needing.

Nor do they care, right?

Wrong. 

Utilities now are starting to break down silos and operate more cross-functionally when planning projects and investments. They must if they want to successfully meet the challenge that DER present to traditional utility resources, especially renewables.

IHS Markit expects 2020’s solar installations – a huge DER component – to reach 142 gigawatts (GW), a 14 percent rise over the previous year and more than seven times the 20 GW of capacity that had been installed a decade ago at the start of 2010. Wind power is on a similar trajectory. The Department of Energy notes that there were 40 GW of total wind capacity in the U.S. in 2010, but the figure jumps to 113 GW in 2020 and will likely reach 404 GW by 2050.

All those renewables reinforce the need for integrated planning within utilities. Supply resources, once only on the transmission system, are now also on the distribution system in increasing numbers. They’re also often relying on highly variable solar and wind as their fuel source and often are customer-owned. What’s more, planning horizons differ between transmission and distribution, although both look at timing from two perspectives: the time it will take to need new investments and the time required to build those new assets.

Most utilities outside California – where transmission projects can take a lengthy 15 years due to regulations and permitting – can finish siting, permitting and construction in fewer than 10 years on transmission projects. Distribution typically looks out five years, the time needed to build a substation, and many other investment decisions are made only one or two years ahead. These differences between transmission and distribution planning horizons are one reason it’s beneficial to see increasing collaboration in these utility areas.

In addition, utilities must now consider hosting capacity. How much solar plus storage can the utility accommodate without incurring upgrades? That’s a question that’s going to bring operations to the planning table, too. 

In this year’s Strategic Directions: Smart Utilities Report survey, 95 percent of respondents said integrating planning functions such as transmission, distribution and resource planning was at least moderately important (14 percent). Nearly half of the respondents said it was very important (46 percent), and 35 percent rated it extremely important. More than half of respondents (53 percent) have already seen their organizations make headway in their integration efforts, while 39 percent are working on it and 5 percent “recognize the need” (Figure 1, below).

This cross-functional collaboration is a non-traditional approach in the utility world, but it’s an important shift to meet DER proliferation.

Staying flexible

As noted earlier, many utilities also now are starting to look beyond their own walls to meet demand. They’re looking at NWAs to grid investments, which are projects that defer or replace the need for system upgrades through non-traditional solutions, such as distributed generation and storage, demand response, load control and energy efficiency measures.

Along with solving problems with less cost than traditional T&D investments, NWAs are a way of integrating more renewables because these solutions tap remote DER resources – such as solar farms or wind generation – plus they leverage demand management and storage resources, which can quickly be brought into play to offset steep declines in renewable energy output due to weather disturbances. Given the decreasing costs of renewable generation, this is a money-saver, too.

“Building new wind and solar plants will soon be cheaper in every major market across the globe than running existing coal-fired power stations,” noted a recent article in The Guardian.

What’s more, NWA solutions are sited to operate locally, and they can be deployed incrementally – in phases – so that the solution scales as load growth occurs.

“Instead of investing in new infrastructure projects based on long-term, uncertain forecasts, planners can deploy modular, flexible non-wires solution portfolios when and where they are needed. This mitigates the risk that large investments will become stranded,” noted The Non-Wires Solutions Implementation Playbook, a how-to guide produced by the Rocky Mountain Institute.

In other words, when a utility sees constraints on a feeder, reconductoring no longer needs to be the go-to action. The utility could add a small solar farm, leverage demand management technologies, install storage – there are many non-wires alternatives, and regulators are starting to insist utilities look into them.

Already, five states – California, New York, Rhode Island, Vermont and Maine – require utilities to consider NWAs in resource planning. In the 2020 Strategic Directions: Smart Utilities Report survey, two-thirds of survey respondents said they see drivers happening now or ahead that will prompt their utilities to consider the NWA approach to meeting system needs.

This, too, will force utility staffers who haven’t left their planning silos to venture out and collaborate more with co-workers.

And since NWAs often involve customers via demand management programs, it is possible that even the utility’s Marketing and PR departments will soon get into a few planning sessions. 


The DISTRIBUTECH content team is hard at work setting up next years conference. Topics such as distributed energy resource management (DERMS), Non-wires alternatives, and utility planning will certainly be on the agenda at next year’s event, which takes place February 9-11 in San Diego, California.