Managing Outages as if the Customers were in the Room

What happens beyond a customer’s field of vision defines the customer experience. During an outage, utility customers want, in priority order, these questions answered:

·         Does my utility know I’m out of power?

·         When will my utility restore power?

·         What exactly caused the outage?

Last July, an annual J.D. Power survey of residential electric customers showed customer satisfaction had reached 719 (on a 1,000-point scale), up from 625 in 2012. The 2017 survey notes outage information directly correlates to satisfaction, and many utilities have created (or plan to deploy) teams focused on customer service.

A similar survey of business electric customers by J.D. Power tallied satisfaction scores for business customers with dedicated account representatives at 824, nearly 100 points higher than customers without an account representative. This seems to mirror what utilities are attempting to do by creating customer experience teams.

So, what’s behind the numbers?

Whether it’s a single outage or an event impacting thousands, utilities react similarly. A call center is among the first places to collect information. If a utility is fortunate enough to have smart meters, it will have a second avenue for reporting customer outages, usually ahead of the customer’s call. With smart meters, utilities will pinpoint outages and get a bead on what’s happened before the customer calls. When residential customers dial the call center during smaller outages, the most customer-focused utilities respond with information obtained from smart meters, previous calls, OMS (which usually have an outage engine) and SCADA. During larger outages, the utility may scale the massive data load from smart meters and rely more on the customer calls, SCADA and field assessments to understand each customer’s situation.

Once the OMS receives the calls, dispatching issues a trouble order to a troubleman or servicer during the day, and, if after hours, performs a callout (hopefully automated) following the appropriate work rules and directing the serviceman to the outage location as predicted by the OMS.

The serviceman arrives and determines if the problem requires additional resources and provides an ETR to a dispatcher who tells the customer and offers a description such as a limb on a wire. If the serviceman alone can’t fix the situation (e.g., a broken pole), that message goes to the dispatcher to secure more resources. For large-scale events, utility managers will schedule resources for 16 hours, with eight hours of rest, while reporting on progress daily, even hourly, until restoring the last customer.

During significant events, damage assessment shifts from line personnel, so they can concentrate on repairing the system, to technicians and support personnel who determine what’s broken and where, reporting it to the dispatch organization (or a smaller organization to reduce dispatch’s workload). They, in turn, provide summary reports to secure the correct amount of resources and material.

Most small outages run smoothly and customers get answers relatively quickly. But during large-scale events impacting significantly more customers, there’s a tremendous amount of coordination to achieve a similar level of customer satisfaction – the kind that affects J.D. Power scores. During large events, a dispatch organization may decentralize and move trouble dispatching to local service centers providing better communications with field resources. The local service centers will hand off non-tactical processes like logistics and planning to others in the organization, so they can concentrate on the tactical plan for safely restoring customer service and communicating progress.

It takes an army of people behind the scenes to not only restore power during a large event but also deliver the kind of information that allays the fears of customers (who may be part of an extended outage) trying to plan their next move. Depending on the size of the incident, that army will range from several hundred to a thousand people working 10- to 16-hour days, ensuring restoration happens efficiently. When customers get reassurance from their utility acknowledging the outage, the restoration time (ETR) and cause of damage, that simple act of communication builds trust. This same information informs media and local officials who then become allies in communicating the important work going on.

Each utility has many processes covering every aspect of restoration. By handing off many of these processes and applying technology, an operations group can better focus on restoration efforts. For example, with damage assessment, many assessors in the field rely on printed maps and paper and pencil to collect and report damage. Automating the collection and restoration process so the planning organization knows in real-time what is broken (and where) would safely expedite the restoration effort and get a community’s power on, faster.

If our customers were at our side, they’d see delays interpreting handwritten damage assessments, especially when non-engineers sent to the field may not distinguish between a transformer and a recloser. Customers would also see the search for missing information or extra time taken to decipher notes or search for broken equipment in the field, which extends an outage. If we invited them into the storm center, they’d see how a manual damage collection process hampers a quicker determination about additional resources that could be brought in from a neighboring utility or state.

I’m not advocating to bring customers behind the scenes. That’s an unnecessary safety risk if nothing else. But it’s incredibly valuable for us to look at everything we do as if the customer was standing alongside us. If that were the case, what would we do differently to better answer their questions and restore power?

About the author: Jim Nowak retired as manager of emergency restoration planning for AEP in 2014. He capped his 37-year career with AEP by directing the utility’s distribution emergency restoration plans for all seven of the company’s operating units, spanning 11 states. He was one of the original co-chairs for Edison Electric Institute’s (EEI) Mutual Assistance Committee and National Mutual Assistance Resource Team and a member of EEI’s National Response Event (NRE) governance and exercise sub-committees. He currently serves as director of Utility Services for ARCOS LLC. Contact him at


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