Spending two full days at the DistribuTECH® 2018 Conference & Exposition in San Antonio, Tex, in January, was an opportunity for the editors of GRiDToday and CCJ ONsite to assess progress as the electricity industry “transforms” from centralized to distributed assets with customer service at the core of the enterprise. Or so all the executives were saying.

The concept of a “smart city” was certainly a prevalent theme, an evolution in buzzy phrases from smart meter followed by smart grid, as was the notion of a “digital utility.” During the keynote talks, a utility executive for a large municipal noted that the company is uniquely suited to be a smart city. An executive from the largest state-owned public utility in the country told the audience it is working to become the first “all-digital utility.” Both have built and are managing significant technology development centers to achieve these goals.

Of course, no one defined what exactly is a smart city or a digital utility, nor did anyone broach what the term smart city might imply about rural areas.

Later in one of the mega-sessions, a representative from one of the country’s largest investor-owned utilities said they were “looking to replace existing assets with new, smarter, and better ones.” This utility is, by the way, one of the largest coal-based utilities, too, which tells you something. The traditional utility business model is to earn a regulated rate-of-return investing in assets over a long time horizon. Smart cities and an “all digital utility” are grand central planning strategies which utilities are comfortable with, even if they are designed for “decentralized” infrastructure.

The muni executive gave an insightful company factoid: Last year the utility had 8470 MW of capacity in operation; in 2020 they expect to reduce that to 7880 MW, while adding 650 jobs. Clearly, those workers are not destined for the powerplants or transmission network. The executive said the company considers the community it serves “energy advisors.” That’s an advisory committee meeting one would probably make any excuse to avoid.

Not your father’s utility bill. The customer-services technology platforms being implemented are nothing like a paper utility billing statement delivered monthly. The hardware model, according to presentations and what was being exhibited on the floor, is the smart phone; the customer experience model is Amazon, and the engagement is intended to be 24/7/365.

Descriptions and demonstrations of these customer/utility interfaces were truly dazzling, with systems controlling a two-way transactional electricity flow interface with the utility, rooftop solar, smart thermostat and HVAC, behind-the-meter storage, electric-vehicle charging station, and more. Customers can chart and alter (or not) behavior, costs, and revenue (if they are selling power back) patterns through data visibility.

Demand side management (DSM), in other words, has come a long way from the utility subsidizing the replacement of an old refrigerator with an efficient one, while the ratepayer plugs in the old one in the basement to keep the beer cold. That was DSM circa 1970s.

Still early days. Despite the promise and potential, the smart-digital transformation is still in its infancy. Utility representatives generally talked more about their “initiatives” and future plans, their technology development programs, and results from initial demo facilities than they did of replicable commercial projects. As one example, the muni utility mentioned above has only one microgrid currently in operation. Meanwhile, the engineers and technocrats grappled with the nuts and bolts of making this stuff work.

Across several sessions addressing microgrid challenges and lessons learned, what was clear is that the one function that essentially distinguishes a microgrid from a conventional power and electrical system serving an industrial facility, for example—the capability to “island” (or safely disconnect) from the utility or larger grid in responding to a disturbance, keep operating, and then automatically reconnecting when the disturbance is cleared—is still the greatest challenge.

In one presentation, the microgrid manager noted that “it was a challenge going from island” operation back to the grid-connected operating state. Further, that seamless transitions work but you may need to shed some load.” That actually doesn’t sound like a seamless transition. Another microgrid operator “was not able to demonstrate transitioning from islanded to grid-connected operation. In this project, one problem was that the battery-storage communication system couldn’t react fast enough to synchronize the battery to utility frequency.

Other challenges mentioned by several with demo-project experience included:

• • Accommodating cloud-induced variability with solar PV systems.

  • Contracting for, and integrating, state-of-the-art components from multiple suppliers into a coherent system design.

  • Understanding and complying with building codes and standards and new standards for microgrid components and grid interfaces, which are still evolving.

  • Control and communications protocols and cybersecurity issues among different subsystems (storage, PV, microturbine/generator, etc).

  • Loop testing hardware with real-time digital simulation (described by one presenter as critical).

  • Handling reactive load profiles and providing reactive power support (one presenter mentioning the application of “smart” inverters).

Finally several C-suite challenges were noted, perhaps unintentionally. For example, a representative of a large nuclear-based utility with a national footprint said they were “pursuing a customer and energy services business model” while also noting that “the customer experience [stuff] is only 5% of the utility’s annual expenditures.” Protecting current revenue sources while pursuing hot new growth areas is always a fundamental challenge for executives of large companies.

One executive noted that “the future is in energy storage.” However, it’s also true that reliable, affordable storage is what could decouple customers from the utility grid, reduce the need for purchased utility power to the emergency backup category, and allow new market entrants to manage a customer’s residential or commercial energy infrastructure. Thus, the real race may be to pay off existing “dumb” assets and retain ratepayers with dazzling new services delivered through an Amazon-like interface before Amazon and others like it dis-intermediate the utility altogether.