Utility outage management: A proactive approach for extreme weather events

Electric utilities have always faced an operational mandate of “keeping the lights on.” When an outage occurs, the customer’s world is put on pause, so it’s no surprise then that power quality and reliability is the most important factor driving customer satisfaction. Consumers also expect utilities to provide real-time updates on any power delivery changes and to respond efficiently to outages. 

The electrical grid infrastructure is undergoing a profound set of challenges. The distribution system is based on dated standards that are struggling in the face of once-in-a-hundred-years-type climate events. Also, the proliferation of Distributed Energy Resources (DERs) means distribution grid operators are faced with new resiliency challenges as intermittent generations serve loads. What’s more, customers are becoming increasingly tech-savvy and expect a high level of engagement throughout their outage journey. 

Extreme weather events are impacting distribution grid outage management functions with increased volumes and velocity of customer outages, and new vectors have forced distribution system operators to trigger customer outages to preserve overall system health and safety. Utilities in regions with recent extreme weather-related outages have seen resources and systems strained over the last decade, bringing to light the need for a more proactive approach to dealing with these events.

The number of extreme weather-related events compound the number of customer outages as well as the number of overall customers

As the frequency, scale, and severity of extreme weather-related events continue to increase, the challenge for utilities to minimize the volume of customer outages increases exponentially. These extreme weather events simply overwhelm utilities and stretch their resources thin as they attempt to maintain the critical electricity infrastructure. 

The Northeast has endured three major hurricanes and tropical storms over the last decade that have caused billions of dollars in damage. One of the constant issues for the region’s transmission and distribution infrastructure is related to the constrained systems which cause significant waves of customer outages.

Hurricane Irene made landfall three times in August 2011, with 6.7 million customer outages reported across 14 states as the storm moved up the East Coast. It took service providers roughly five days to restore service to 95% of the affected customers. 

In October 2012, Hurricane Sandy made landfall near Atlantic City, causing 8.2 million customers to lose power across 21 states. New Jersey was hit hardest, with 65% of their customers losing power. Nine days later, 10% of New Jersey customers were still without power. 

Hurricane Isais made landfall in North Carolina in August 2020 before stretching up the East Coast. The storm system caused millions to lose power, with a peak of 2.7 million customers without electricity.

Utilities are bracing for increased frequency and intensity customer outage events

A derecho rolled across the Midwest in August 2020 carrying with it high winds, heavy rain, and large hail. The fast-moving group of severe thunderstorms raced 770 miles from Eastern Nebraska through Indiana within the span of 14 hours. The storm left behind a trail of destruction totaling over $7.5 billion, with hundreds of thousands stranded without electricity. 

During the storm, an estimated 1.9 million customers experienced a service interruption with a coincidental peak of at least 1.2 million. Within the Chicago metropolitan area, 800,000 customers lost electric service as a result of the storm system, with up to 100,000 waiting several days for resumption of service. 

The velocity of this storm system created a surge of customer outages that overloaded the local utilities’ ability to respond. The increasing frequency of these fast-moving systems requires a rethink to how utilities approach their typical storm response and response readiness. 

Severe weather events require distribution system operators to deploy additional tools and system features to deploy proactive outage events in an efficient and effective manner 

The series of severe winter storms that swept across most of the U.S. in February 2021 brought record-breaking low temperatures as well as blankets of snow and ice, disproving the notion that electricity supply can meet demand through market and regulatory drivers alone. Areas of Texas reported their longest streak of days with a temperature below freezing. 

The cold temperatures wreaked havoc on the state’s natural gas and coal-fired power plants as well as grid-scale wind farms resulting in a peak loss of approximately 52,000 MW (48.6%) of generation capacity. With demand spiking up to almost 68,000 MW, ERCOT initiated rolling system outages to shed 20,000 MW of load. Combined with the physical damage to the transmission and distribution infrastructure, this left 4.5 million customers without power. 

The reality is that utilities face supply shortfalls due to external factors in a deregulated market. As highlighted by FERC after the 2011 ice storm, local utilities must be prepared for load shedding to prevent widespread, uncontrolled system instability. The same situation that nearly happened 8 years later when the Texas interconnection was less than 5 minutes from a cascading blackout due to additional generators tripping on underfrequency conditions. 

Utilities have approached these outages with the following key concepts:  

• Avoidance: The best outage outcome is the one that that never occurs.  
• Minimization: Reduce the length of outages and the number of customers affected by the outage
• Response: Establish pro-active, coordinated, and two-way communications between customers and field crews 

These factors played an important role in addressing these extreme weather-related events. Still, a significant number of customers suffered from these events. As a result, utilities experienced high costs due to reconstruction of the grid and fines for drops in reliability and satisfaction scores, again highlighting the need for a more proactive approach. 

Three ways utilities can build an improved strategy for proactive outage management 

1. Invest in grid hardening for increased system resiliency: Utilities should be reviewing and prioritizing investments to both grid infrastructure and back-office systems. Make investments in resilient grid infrastructure, including assets and distribution automation networks, as well as those focused on improving IT and OT systems and integration scalability to handle increased number of outages and to improve estimated time to restore calculations during storms. 

2. Expand advanced distribution grid operational tools to optimize outage restoration: Utilities should prioritize adding tools that operators can use to manage outage and restoration activities. The distribution operator of the future relies on a unifying platform called an Advanced Distribution Management Systems (ADMS) to centrally monitor, manage, and maintain the grid. By bringing foundational (and historically separate) operating technologies together (D-SCADA, OMS, DMS), an ADMS platform is a powerful method of combatting outages:

• Self-healing features (such as fault location, isolation, and service restoration (FLISR) and automated switch order management) expand the capabilities of distribution automation network to minimize customer outages
• Rotating load shed functionality  

3. Incorporate analytics to improve system reliability and restoration insights: Specifically, utilities should tap into cross-system datasets to improve outage insights in three key areas: 

• Leveraging data to drive maintenance to reduce outages 
  
  Utilities should adapt legacy asset management practices to align with leading ISO 50001 standards, helping to improve organizational capabilities and risk-based decision-making to reduce unplanned failures. 
  
  This includes asset predictive failure models that identify vulnerable assets based on actual load and historical device failure signatures—leading to a needs-based, pro-active repair or replacement. This technique, known as condition-based maintenance, improves on more traditional approaches (age-based, run-to-failure). 
  
• Studying effects of weather on their service territories to inform outage planning 
  
  Utilities are integrating third-party weather forecasts into outage prediction platforms, giving grid operators granular service territory outlook (e.g., square mile-level, circuit-level) of likely outages. This intelligence allows utilities to pre-mobilize field restoration efforts before outages occur. 
  
  Combined with network connectivity modelling (meter-to-transformer, transformer-to-phase), utilities are better prepared to contextualize and achieve a more complete view of outage events as they emerge. As DER penetration increases, utilities are further able to measure and manage the ‘masked load to support circuit restarts.  
  

• Increasing the frequency, specificity, and accuracy of communicating estimated time to restoration (ETRs) with customers 

Utilities are increasing accuracy and precision of outage events through analytics. Verifying outages and metering pinging verifications allows utilities to corroborate reported outage events, allowing utilities to prioritize outage response efforts. 

This improved validation omits customers who have already had power restored and identifies probable outages that may not have been initially reported. Analytics further allow utilities increased precision on estimated time to restoration (ETR) by applying localized factors such as location, equipment, and historical performance.   

Severe weather events are increasingly imposing strain on electric utilities’ grids and systems, resulting in more customer outage events. Those utilities have an opportunity as technology maturity and investments increase grid/digital hardening measures with additional data sources, leading to insights that better prevent, predict, and respond to future outage events.