Navigant Research Blog

Mobile Utility Solutions Move Beyond Field Crews

— April 15, 2015

The market for utility IT systems is large and growing. Navigant Research estimates that nearly $9.5 billion will be spent globally this year on everything from meter data management (MDM) and customer information systems (CISs) to advanced distribution management systems (ADMSs), outage management systems (OMSs), and new analytics solutions. (Our forthcoming report, Smart Grid IT Systems, will cover these technologies in detail.)

Mobility is a key part of this expansion. Utilities today want their workers to have access to systems data wherever they are. While this has long been true for mobile workforce management systems (MWMSs), mobility requirements are now extending to a multitude of systems.

As IT systems are increasingly integrated with each other and MWMSs, field crews can not only communicate instantly with their peers over mobile devices, but also upload critical, accurate data to central office systems from the field. Photos can be taken and uploaded in real-time, providing global positioning system (GPS) coordinates of a given grid device as well as visual information and nameplate data. Asset management systems (AMSs) and geographic information systems (GISs) have never before had the benefit of such accurate and granular data.

In Real Time

Safety measures can also be enforced by mobile systems. IBM and Apple have announced an iPhone solution that (among other things) can require a worker to view safety guidelines before performing certain tasks. The app can also ensure that the worker has appropriate, up-to-date certifications before beginning the job. It can find subject matter experts or managers in the geographic vicinity if the onsite crew doesn’t have the needed expertise.

On the customer side of the equation, utilities are recognizing the need for greater, more frequent engagement. Mobile applications tied in with MDM systems and CISs allow customers to easily check their mobile device for information on usage and bills or to participate in demand response events, giving them more visibility and control over their energy use.

Utilities are also adding social media accounts and using them to interact with consumers—a field worker can post to Facebook, for example, to advise customers when an outage is expected to be over—and keep posts up-to-date in real time readily from the field. The connected employee and real-time system access are revolutionary advances in utility IT; the possibilities for utilities to gain real worker and ratepayer efficiencies are endless.

Mobility at a Price

These new possibilities don’t come cheap, though. In addition to mobile device and communications costs, the integration expenses for utilities that upgrade one or several systems in order to achieve these benefits can be high. In a highly competitive market, the prices for utility software solutions generally are holding steady, even as functionality grows. But the number of system interfaces and the complexity of integration are increasing, as well. Although smaller utilities may be challenged to make these upgrades, in the long run, mobile access will be as common a tool for utility workers—including those in the office—as it is today for many other industries. This mobility is a key aspect in enabling the energy cloud, which promises to connect stakeholders in each link of the energy value chain.


As Smart Grid Spreads, Substations Go Automated

— February 17, 2015

Navigant Research estimates that there are approximately 47,000 distribution substations (D-subs) across the United States, including privately owned substations (such as for large commercial sites or military bases), and another 12,500 transmission substations. We understand that the vast majority of critical transmission substations are automated—that is, they are connected to utility operations centers by communications networks, which allow personnel to monitor and control what happens inside these substations.

When it comes to the distribution grid, however, the level of visibility and automation in substations varies widely. Some utilities report that they have brought fiber to virtually all of their substations; others indicate that their visibility into the distribution grid is limited. We know that this is changing and that the percentage of D-subs with connectivity and automation capabilities is growing, but we also know that those sites historically served by leased copper lines for supervisory control and data acquisition (SCADA) are now in need of a new solution as telephone companies abandon their legacy copper networks.

Our present forecasts for automated substations estimate that total distribution grid substation connectivity was approximately 34% at the end of 2014; over the next 8 years, Navigant Research expects D-sub connectivity to exceed 50%.

Whither Substation Automation?

These figures are important for quantifying the evolution of the smart grid. You can’t have an estimate for automated substations if you don’t know how many substations there are to begin with. Absent government databases, though, it can be tough to nail down infrastructure statistics like these, and so I’m turning to the readers of this blog.

I’d like to invite readers to share anecdotal or specific data related to a few key questions related to overall infrastructure and the status of smart technology deployment.

What do you think? What percentage of your distribution substations are connected?  What technologies (fiber, microwave, T-1, etc.) are used for that connectivity? How quickly, if at all, is your company investing in D-sub connectivity, and why? Interesting anecdotes related to the topic of substation automation are welcome! I hope you’ll take the time to send your thoughts and data points to

Next time around I’ll explore distribution feeder automation and other distribution grid smart technology. Below is our forecast for distribution substation connectivity, which underlies the networking forecasts in the Navigant Research report, Smart Grid Networking and Communications.

United States Distribution Substation Connectivity Outlook

(Source: Navigant Research)


New Relay Technology Is Transforming the Grid

— December 9, 2014

A major transformation is occurring in the electric transmission industry, as new digital technologies, high-speed communications, and big data analytics are being deployed to improve transmission grid reliability and resiliency.  This transformation starts at the basic level of protective relays – technology that has been utilized on the transmission grid for years.  These devices are beginning to evolve from mechanical and solid-state relays to next-generation digital relays that perform all of the standard system protection functions, they but also have new digital capabilities for phasor measurement units (PMUs), data collection, and synchrophasor analysis that are largely untapped in today’s transmission utility market.

My conversations with major vendors, such as Schweitzer Engineering Labs (SEL), Alstom Grid, ABB, and General Electric (GE), as well as major utilities, indicate that the new technologies will change the way transmission operators detect and respond to transmission system disturbances and outages.  Now that network operators have the ability to detect sub-second disturbances in phase angle and voltage (which lead to outages and other reliability issues), with data coming in 30 to 60 times per second, a new major market for smart grid data analytics, visualization tools for the operations center, and communications is opening up.  Recent information on the nine U.S. Department of Energy smart grid demonstration projects in the United States, funded by stimulus grants, suggests that utilities are in the early stages of deploying these technologies, and that next-generation synchrophasor analytics, high-speed fiber communications systems, and high-speed sub-second automation solutions are in the early stages of adoption, at best.

Current Locations of PMUs on North American Power Grid 

(Source: North American SynchroPhasor Initiative)

In mid-October, I attended the 46th Western Protective Relay Conference (WPRC) in Spokane, Washington.  Along the Spokane River, salmon were rising in the afternoon to a late season fly hatch.  I’ll have to admit that I had not expected a conference featuring three days of technical papers that included some true power engineering discussions of second derivatives, Fourier transforms, phasor analysis, and phase angle diagrams, plus a couple of presentations on the use of comparative synchrophasor analysis for management of the transmission grid.  The 500-plus attendees included a mixture of vendors, experienced transmission planners and engineers, and a large number of new transmission engineers and trainees that were attending to learn from the experts from across the industry.

As advanced digital protective relays are deployed across the grid, consumers will benefit from improved reliability and grid resiliency.  Transmission utilities will also benefit, as they look to these lower-cost systems to add additional synchrophasor coverage and capabilities at a much lower cost.


Utilities Warm to Cloud-Based Smart Grid Analytics

— August 5, 2014

Managed services for smart grid applications — also known as smart grid as a service (SGaaS) — haven’t exactly lit a fire under utility executives.  Despite the numerous advantages to outsourcing non-core activities like communications, software applications, monitoring, etc., many large utilities, citing security, control, and economics, prefer to keep these functions in-house.

But as smart grid deployments extend beyond the largest utilities, it seems likely that organizations constrained by finances or personnel will be obliged to consider the SGaaS model if they want to take full advantage of smart grid technology.

Vendors are repackaging their solutions in a spectrum of managed offerings, from hosted to managed to full business process outsourcing.  And cloud service providers, including Amazon, Microsoft, and Google, are actively courting utilities’ business.

On July 14, Itron announced that it has selected Microsoft’s Azure cloud platform for its managed Itron Analytics solution.  Microsoft Azure will maintain the infrastructure, allowing Itron and its customers to focus on the analytics.  Itron says its analytics solutions can be installed locally, run by the utility in the cloud, or operated and managed as part of Itron’s Total Services.

The Whole Enchilada

Itron’s Total Services boxes up the metering, communications, and meter data management, along with analytics, in a fully managed offering.  In other words, Itron will not only turn the knobs, but will also respond to the information coming in.  Texas New Mexico Power (TNMP) in Lewisville, Texas engaged Itron to provide meter data analytics for its 230,000 meters earlier this year.

TNMP told me that “a smart meter can trigger hundreds of alarms; our staff may not have the expertise to best respond, whereas Itron’s analysts do have that proficiency.”  TNMP is also working with ABB’s Ventyx unit for an outage management system (OMS) that will be hosted and administered by Ventyx.

Hefty Growth Ahead

Navigant Research’s report, Smart Grid as a Service, forecasts that the SGaaS market will grow strongly over the next decade.  Our forecast includes a host of managed services for utilities, including home energy management, advanced metering infrastructure (AMI), distribution and substation automation communications, asset management and condition monitoring, demand response, and software solutions and analytics.  We expect to see a $1.7 billion market in 2014 growing to more than $11 billion in 2023.  Software solutions and analytics sold under a software as a service (SaaS) model are the largest category of SGaaS spending today, followed by AMI managed services.

Annual SGaaS Revenue by Category, World Markets: 2014-2023


(Source: Navigant Research)

Challenges to the model do remain, however.  Most notably, the rate of return model that most investor-owned utilities work under encourages them to make their own capital and personnel investments.  But for smaller utilities (e.g., cooperatives and municipals here in the United States), the speed with which solutions can be deployed, and the absence of large upfront investment, will be attractive.


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