In 2014, Consolidated Edison announced an ambitious project to defer a $1 billion substation in its congested urban territory across parts of Brooklyn and Queens, using a variety of technologies ranging from batteries to smart thermostats.

Since then, there has been momentum building to look at demand-side resources as cheaper alternatives to large infrastructure upgrades. New York, with its Reforming the Energy Vision proceeding, is leading the charge, but it is not the only state thinking about valuing distributed resources in a new way and comparing those with traditional grid investments.

There are projects proposed or in operation from California to Michigan to Florida that aim to defer the cost of expensive grid equipment such as conductors, transformers and substations and use demand-side resources, such as demand response, energy efficiency and energy storage, in those pockets instead.

Using energy efficiency to defer T&D upgrades has been common in some states for years, but the new wave of non-wires alternatives is leveraging a mix of more sophisticated demand-response controls and grid-edge technologies that allow utilities greater precision in dropping load where needed to get the most out of grid assets.

“At the end of the day, you don’t want a demand-response program across a service area,” Robert Sherick, manager of power systems technology for Southern California Edison, said during a presentation at DistribuTech 2016. “It does matter what circuit you’re applying it to.”

Eventually these projects will not only help with growing load, but also alleviate issues due to high levels of renewables, and eventually be integrated into distribution planning. The latter vision is many years away, however.

“To efficiently employ [distributed energy resources] for these 'front-of-the-meter' or utility benefits, DERs must be part of the planning process, a practice rarely incorporated into distribution planning and even more rarely involving third-party integration or ownership of these resources,” Ben Kellison, director of grid research with GTM Research, wrote in his latest report, Unlocking the Value of Distributed Energy Resources 2016: Technology Strategies, Opportunities and Markets.

One-off projects, for now

Currently, the projects are about addressing small pockets of existing congestion because of aging infrastructure or isolated areas of significant load growth. Comverge, for instance, is working with Central Hudson, a New York utility with about 300,000 electric customers. Comverge will help Central Hudson roll out a bring-your-own-thermostat program to three areas with distribution congestion that serve nearly 50,000 customers. The investment should defer substation upgrades for at least five years, and maybe longer.

“We expect to see more and more of these projects,” said Steve Hambric, VP of strategic sales and operations at Comverge.

As part of New York’s REV, each utility had to define at least one non-wires alternative project, which is separate from the REV demos. REV demos are meant to test new business models and technologies, while non-wires alternatives can be rate-based.

At this point in time, the nature of non-wire alternatives makes them different from some other ways that demand response is evolving as a market resource. In California, for instance, behind-the-meter resources like battery storage and demand response are being bid into wholesale markets as part of the state's new Demand Response Auction Mechanism, or DRAM. Those assets will also have to help with resource adequacy for utilities, meaning that the resources will have to provide some level of load reduction when the local utility will need it.

But the non-wires alternatives are different. They are assets that are deployed by the utility or a utility-run demand response program that is just for distribution relief, rather than assets already owned by third parties.

Pacific Gas & Electric is testing the concept of non-wires alternatives in Yuba City, Jackson, Tracy and Fresno. The utility expects to have substantial customer growth in those areas and wants to save up to $2.5 million by deferring substations in each area for three to five years.

“This will allow us to enhance reliability for customers with the same level of spending,” Richard Aslin, a demand response expert with PG&E, said in a statement. The money left over from the deferred substation upgrade can be used on other projects.

PG&E will target upgrades such as smart thermostats, lighting and pool pumps. Unlike New York utilities, California’s large utilities have smart meters, which makes it easier to target customers with the load profile that will help the utility meet its targets for the program.

A new future For utility planning

In New York, smart meters are coming, but not before the utilities must move forward with their first non-wires alternative projects. Con Edison is already underway with its BQDM project and has proposed a second project in the Brooklyn neighborhood of Bensonhurst.

Starting in 2021, Bensonhurst will see the load exceeding the design capability of its feeder, but only for a few hours on a couple of days per year. By 2025, it will be more hours per day, but still only about two days per year. The utility will require about 45 megawatts of resources similar to the ones it's using in BQDM to support the feeder.

In New York, many of the non-wires alternatives programs are fairly small. For instance, the utility NYSEG, a subsidiary of Avangrid, just put out an RFP for its non-wires alternatives for about 5 megawatts. But these initial projects are meant to be the first step in an entirely new way of doing business under REV.

The challenge and potential solution of non-wires alternatives looks similar across the country, but with varying degrees of sophistication. For some utilities, such as Indiana Michigan, a subsidiary of American Electric Power, the focus is more on efficiency than next-generation demand response. Some states, like Vermont, have mandated years ago that utilities use at least some efficiency investments to defer distribution upgrades.

But moving forward, the resources will become more complex, and so will the challenge of valuing them compared to traditional investments. The holy grail is to incorporate resources such as demand response and energy storage assets into distribution planning, rather than having one-off projects to defer upgrades.

Smart meter data is just a very basic layer of information. Grid planners will also need improvements in GIS, better distribution modeling and improved data quality on feeders that could be served by non-wires alternatives. As with value-of-solar tariffs, there is also the need to value cost mitigation, risk and non-monetary benefits on the feeder level, said Kellison.

That process is underway in California, where the state has set up a locational benefit methodology for the utilities to work from. “It has a long way to go,” said SCE’s Sherick, who is working on the utility’s Integrated Grid Project.

The project is looking at the impact of high levels of preferred resources, such assolar on the local distribution system and how to balance that with demand response. Valuing demand response depending on feeder and time of day is painstaking work, and is just starting to be understood by even the most advanced utilities.

“It’s not something we’re used to doing,” said Sherick. But by evaluating the price and value on circuits that could benefit, utilities like SCE hope they can unlock a whole new opportunity. Central Hudson, for instance, hopes to integrate the findings from its non-wires alternative into its forthcoming efficiency marketplace to leverage more behind-the-meter resources exactly where they are needed.

To create that value, it will likely require marketplaces of some sort at the distribution level, and not just the wholesale level. “When you make money on the wholesale market, it can create issues on the distribution level,” noted Sherick.

And despite the potential value, it will probably never be a utility-wide endeavor, given the complexity and cost. Instead, planning tools, when they are more developed, would be deployed in a more surgical manner in troubled regions on the distribution grid.  

The lack of commercial solutions over the last several years have led some utilities to partner with traditional providers to develop functionality for traditional planning tools, says Kellison, while others have worked to customize and commercialize new suites of software such as OpenDSS from EPRI and GridLab-D from PNNL.

“Complexity is not stopping a variety of utilities from working on developing the necessary planning and economic tools,” said Kellison. “We see modeling and simulation work to site DERs not just in California and New York, but also elements of these efforts at PNM Resources in New Mexico, Avista Utilities in Washington, Detroit Edison and Pepco in the Mid-Atlantic.”

Although many utilities are led by regulatory mandates to value these resources, others like Avista see that the future will require these capabilities and don’t want to be behind the learning curve when they need it.