Hurricane Irene and Superstorm Sandy, almost a year apart, walloped the east coast of the United States like a one-two punch. Combined with other serious storms within the same time frame across North America, they brought to the national fore a renewed political focus on the resiliency of the electric grid, including what can be done to better harden it against outages and what is necessary to better prepare customers for them when they do occur.

Severe weather is the leading cause of power outages in the U.S., according to a new White House report released in mid-August of this year.¹ ‘Between 2003 and 2012, roughly 679 power outages, each affecting at least 50,000 customers, occurred due to weather events,’ the report noted. Over the same period, ‘weather-related outages are estimated to have cost the U.S. economy an inflation-adjusted annual average of $18 billion to $33 billion.’ And in 2012 alone, the U.S. ‘suffered eleven billion-dollar weather disasters – the second-most for any year on record, behind only 2011.’² Two examples stand out:

1. 2012’s Superstorm Sandy left 8.5 million customers in the U.S. without power
2. Hurricane Irene, in 2011, was responsible for 6.5 million U.S. customers in the dark.³

In Canada, too, the weather experience has been similar. A flash flood in July in Toronto resulted in the province of Ontario’s largest blackout since 2003, and severe flooding in June 2013 in Calgary, Alberta, a city of 1.1 million people, took out electricity to much of the city during the flood’s peak.⁴

While electric utilities can’t promise to be able to completely avoid power outages from severe weather, technology and lessons learned from previous storm experiences can assist utilities in preparing for the next big storm.

The Three Ps
Of the three Ps – planning, preparation and prevention – the latter is nearly impossible without rebuilding much of the grid, but planning and preparation can be continually updated, both by incorporating lessons learned and by utilizing technology and in-application data analytics.

If you think about it, the U.S. electric grid alone – which connects more than 144 million end-use customers with 5,800 major power plants and includes more than 450,000 miles of high voltage transmission lines⁵ – can hardly make itself completely impervious to every assault of the increasingly numerous and severe storms affecting the power grid. And continue they will: the National Climate Assessment says the incidence and severity of extreme weather will persist, caused by climate change.⁶

By meshing weather forecasts and recorded damage from previous, similar storms, for example, and analyzing it, utilities can better predict potential damage prior to the onset of the storm, and do their best to prepare for it or pre-place the right people and resources in areas the utility predicts will sustain the most damage. Further, using the same predictive model, the utility can be better able to provide more accurate, outage-specific Estimated Time of Restoration (ETR), key information specific to affected customers and other stakeholders.

Further, robust outage management and distribution network management tools will assist by providing self-healing, autonomous restoration where it is possible to unfaulted line sections, as well as full visibility across the utility’s entire grid to more quickly determine the outages problems and address the utility’s needs to operate safely, securely, and efficiently during outages while reducing outage durations.

Communication with stakeholders is key
After Hurricane Irene in August 2011 and an early autumn snow storm in October, both of which caused widespread damage in New Jersey, Emergency Preparedness Partnerships (EPP) prepared a report on the emergency preparedness of New Jersey electric distribution companies for the New Jersey Board of Public Utilities (BPU).⁷

In it, EPP pointed to communication as a crucial item in its recommendations:

“The entire community is dependent on power, therefore, information about power outages and restoration is critical. Effective communication is a key component to the success of an EDC’s [Electric Distribution Company’s] restoration process. No matter how successfully an EDC conducts its restoration activities, poor and inaccurate communications will outweigh many of the positive aspects of those efforts.”⁸

Utilities, by and large, recognize this, and many have turned to social media and mobile channels as customer preferred communication tools during outages. Some rely on outage maps on their websites, and others also use Twitter and Facebook to relay information and ETR updates. “The reality is, you have to get involved where your customers are. It’s table stakes. You have to do it,” one utility’s digital and social media strategist told us about his company’s move into social media channels.⁹

In the case of storms, the two-way, instantaneous communication available through mobile and social media channels make them great tools for receiving photos of damaged poles and wires (along with data/time stamps and GPS coordinates, in some cases) and outage reports. These channels also offer utilities the ability to visually communicate restoration effort updates: During Superstorm Sandy, Con Edison (Con Ed) also used social media channels to show the storm restoration process as it was occurring, filming on-the-ground videos of employees showing and talking about what they were doing to restore power in Lower Manhattan, Staten Island and other areas, and then posting them on YouTube. The uptake on these videos was tremendous.¹⁰

The EPP also told the New Jersey BPU (and this has been reiterated in other reports following Superstorm Sandy) that it is imperative that utilities provide a Global ETR (the time at which power to all customers will be restored) within 24 hours of the end of a storm event.11 Other utilities, too, are looking more closely at customer communications during outages. On May 31, 2013, Southern Maryland Electric Cooperative, Inc. (SMECO) filed a report on planned improvements to communications systems with the Public Service Commission of Maryland following outages in its service territory from the June 29, 2012, derecho.[[12]]

In it, the cooperative electric utility noted: “One of the lessons learned from the June 2012 Derecho was that SMECO should strive to provide a more granular and reasonably accurate Estimated Time of Restoration sooner during major outage events.” But it also raised an issue many utilities are grappling with, the difference between providing a more accurate global ETR sooner, and providing speculative customer-specific ETRs. “The purpose of releasing ETRs is to allow a utility’s customers to plan and take appropriate action to protect their property and ensure the health, safety and convenience of their families,” the utility wrote. “It serves no useful purpose to release inaccurate or speculative customer-specific ETRs. Misinformation is more likely to lead to frustration and misdirected customer efforts based on that information.”

That said, the cooperative is working to be able to manage customer-specific ETRs at the substation and feeder level within its outage management system. This, it says, would give SMECO the means to begin providing customer-specific ETRs earlier in an event than it can currently. It expects to be able to begin using this new functionality by the end of 2014.

Using technology effectively
As noted earlier, robust outage management and network management tools can also provide a utility with full visibility across its system (aiding in more effective and immediate restoration efforts in order to reduce, wherever possible, outage durations), as well as providing self-healing, autonomous restoration where it is possible.

One large electric utility in the southern U.S. began upgrading its storm response toolbox nearly a decade ago, with an eye to increasing its visibility across the grid with the aid of real-time, decision-driving data. Its service area is subject to a variety of severe weather issues ranging from hurricanes, violent thunderstorms, heavy winds and tornadoes to wildfires, ice and snow, and it’s important that it be able to respond quickly and efficiently when a storm takes out the power.

Back in the early 1990s, the utility was relying, like many others, on a series of paper maps on the walls, and printed work tickets. While system operators were extremely familiar with their areas, there was little by way of electronics to help them to quickly aggregate information on outages.

Throughout the years, the utility has continued to upgrade its outage management and distribution management systems, integrating them with its corporate geographic information system (GIS), SCADA, mobile dispatch and advanced metering infrastructure (AMI) systems to better populate its real-time, end-to-end view of its distribution network. In particular, integrating GIS allows it to maintain a single environment for near real-time field data to better support outage management, system analysis, customer information and a web-based viewing platform, while integrating its AMI system allows the operations center to know, on a more granular basis, the extent of the outage.

Being able to combine source data, model data and map data in one place is extremely important in today’s outage management, allowing operators to deal with outages, quickly dispatch crews, and give customers estimated restoration times. The more granular data collected before, during, and after the event also allows the utility to proactively identify , analyze and address issues before the next storm outage event. Modern Outage Management Systems must be storm-proven and designed from the ground up to scale to the worst possible conditions. They must support the ‘fire hose of data’ coming at it in order to process timely and accurate information for the utility to safely and quickly respond. Equally important, the systems must provide customers with their specific information so they can be assured they being taken care of.

In terms of providing ETRs, the utility has come a long way from the good old days of ‘best guesstimates.’ System-embedded analytics allow the utility’s operators, using table-driven parameters to factor in variables (such as shift and season) and ‘what if’ scenarios, to improve estimates of crew staffing requirements, quickly determine appropriate resources needed and optimize mutual aid strategies.

Operationalizing an understanding of the customer
But while the behind-the-scenes technology has increased the utility’s operational efficiency and reliability, it is important to remember the third part of the equation: customer satisfaction.

Most utilities would concur that the operational functionality of its outage management system that its customers care about the most is twofold: an avoidance or reduction in the duration of the outage, and accurate communication regarding the outages, including cause and estimated time of restoration.

Regulators would agree, as has been shown time and time again after the severe storms and widespread damage caused in the past two years alone.

About the Author

Bradley Williams is Vice President of Oracle Utilities Global Business Unit’s Product Management responsible for Outage Management, Distribution Management, Mobile Workforce Management, Work and Asset Management, and Load Analysis utility applications and Smart Grid Strategy.

Brad had more than 24-years utility technology innovation experience. Prior to Oracle, Brad was a Research Director in Gartner’s Energy & Utilities Industry Advisory Services focusing on utility applications of GIS, SCADA/EMS/ DMS, Outage and Work Management, and Transmission & Distribution Asset Management research. Prior to being a Research Analyst, Brad directed PacifiCorp’s T&D Asset Management responsible for long-term asset strategies and Business Technology that developed and implemented comprehensive IT investment programs. As Director of T&D Infrastructure Planning, Brad was responsible for PacifiCorp’s Subtransmission Planning, Telecommunications, and operations Technology Development groups. Brad also worked at Southern California Edison for 10-years where he was involved in transmission system planning, distribution automation, and reliability programs.
 

References
¹ Economic Benefits of Increasing Electric Grid Resilience to Weather Outages, Executive Office of the President. The White House, August 2013
² Ibid.
³ Ibid.
⁴ “Coast to coast, a power grid stretched thin,” Shawn McCarthy and Josh Kerr, The Globe and Mail, August 14, 2013.
⁵ Economic Benefits of Increasing Electric Grid Resilience to Weather Outages, Executive Office of the President. The White House, August 2013
⁶ Ibid.
⁷ “Final Report: Performance Reviews of EDCs in 2011 Major Storms,” Emergency Preparedness Partnerships for the New Jersey Board of Public Utilities, August 9, 2012.
⁸ Ibid.
⁹ Harnessing the Value of Social Media, Oracle Utilities, June 2013.
¹⁰ Ibid.
¹¹ “Final Report: Performance Reviews of EDCs in 2011 Major Storms,” Emergency Preparedness Partnerships for the New Jersey Board of Public Utilities, August 9, 2012.
¹² “Report of the Southern Maryland Electric Cooperative, Inc. on Planned Improvements to Communications,” Case No. 9298, filed before the Public Service Commission of Maryland, May 31, 2013.