Mike Fish’s job is all about change.
The manager of technology services for Phoenix-based Salt River Project (SRP) is tasked with implementing a revolutionary process for one of the most progressive public power utilities in the country. Specifically, Fish is working to integrate data from SRP’s smart meters (140,000 and counting) into the utility’s back-office processes—particularly customer service and billing.
In this effort, Fish and his colleagues at SRP have learned many things about the promise of smart-grid technology, but one lesson stands out: “It won’t work the way anybody tells you,” Fish says. “There is both real promise and hype. The devil is in the details, and you have to figure out for yourself how it really works in your own system.”
In practical terms, this means utilities will encounter unique challenges when integrating smart-grid data into their back-office processes, such as customer information systems (CIS), outage-management systems (OMS), network operations, and asset management in general. Utilities will need to retool those processes to various degrees, depending on the age and capabilities of their systems, and the type of middleware they put in place to manage the flood of new data. And because the smart grid itself is an evolving concept, its technical structure likely will change over time—requiring software, processes, and strategies to be adaptive and flexible.
“The smart grid is very much in its infancy,” Fish says. “What type of information you will get from it, how you will get it and how you will use it are questions that are still in discussion. But the only way to answer those questions is to figure out where you want to go and start deploying systems. You have to get your feet wet.”
The smart-grid vision is evolving quickly as utilities explore and experiment with the possibilities of various technologies. What began for many companies as an effort to reduce metering costs and implement time-of-use (TOU) rates for more customer classes is growing into an honest-to-goodness transformation for the utility industry.
“The call centers of the past were just call takers,” says Joseph Thomas, associate vice president and general manager of client fulfillment at United Illuminating in New Haven, Conn. “Now they have more information to do analytics, and they are becoming advisers and consultants to the customer. It is a significant transformation for the utility.”
The nature of that transformation is difficult to predict, however, because utilities still are learning about the potential applications of smart-grid systems. “As you deploy these systems and get more familiar with the data they gather, you come up with new ideas and processes that can use the information,” Thomas says. “It’s an evolving process, and is part of a strategy for moving forward.”
The obvious applications, after time-of-use billing and demand-responsive pricing, include remote connect/disconnect functions, visibility into outages, power-restoration capabilities, and more efficient asset-management and work processes (see “Workforce Automation: Where Rubber Meets Road,” p. 68). All these applications theoretically are possible using today’s smart meters and distribution-automation technology. But making them all happen within a utility’s existing back-office infrastructure is another matter altogether.
“If the CIS doesn’t play well with others, you have to build a new integration platform to plug into the new data source,” says Greg Taylor, a senior manager with Black & Veatch Corp., working on Hydro One’s AMI project in Ontario. “The system mirrors the process. You really have to put on your thinking cap, and go through all the processes to see what the changes mean to the system.”
Even seemingly simple requirements, like getting the CIS to poll meter reads from a meter-data management (MDM) system rather than waiting for them to be manually entered, can confound existing back-office technology. Some newer CIS platforms easily might be configured to accept data from an MDM and produce bills accordingly, but others will require coding changes—perhaps significant ones, depending on the vintage and architecture of the system.
“Things like on-demand power-status requests and the ability to remotely disconnect services require a more sophisticated interface than has been needed in the past,” says James Strapp, an associate partner in the energy and utilities group at IBM Global Business Services in Toronto. “And currently no CIS is able to provide all the services needed for hourly interval data and TOU rates. That has to come from a separate application.”
In most cases, the application that handles smart-grid data for utility CIS is some kind of MDM system. How it works depends on the types of metering systems involved and the functions required. For example:
• In Ontario, the provincial government owns the MDM system, which is designed around the eMeter platform. IBM built the system and operates it under contract, eventually as a central hub for all 90 retail utilities in the province, which are required by Ontario law to provide TOU billing. Customized “gateway” software will arbitrate between the data formats of the utilities’ diverse metering systems and the central MDM system, and between the MDM system and the utilities’ CIS and billing systems.
• At United Illuminating in Connecticut, the metering vendor, CellNet, hosts the MDM and provides validated meter data to UI’s back-office systems—including its SAP customer-information system, Nexus online customer-service portal, and Aspect interactive voice-response system. The utility recently began deploying remote connect/disconnect features.
• Southern Co. has deployed about 100,000 advanced meters and has issued an RFP for about 800,000 additional smart meters. An Itron MDM system supports TOU meter reads and provides data to Accenture, which hosts Southern’s CIS. Southern is working with Accenture and Itron to develop more advanced AMI features such as remote connect/disconnect.
• At SRP, a home-grown MDM application compiles data from the utility’s Elster EnergyAxis AMI system and presents it to SRP’s legacy CIS and billing systems. SRP already has implemented time-of-use rates and remote-connect/disconnect functions, and plans to integrate the system with Web-based customer services.
In each case, the MDM system is designed primarily for meter-reading and billing processes. To what degree utilities’ MDM systems will serve real-time operational functions, however, is still an evolving issue. In some cases—such as United Illuminating’s CellNet-hosted system—the MDM system interfaces with outage-management processes, sending trouble flags to back-office systems to trigger a service response.
“In the past when you lost a phase or had an alarm, you wouldn’t know until the following month’s meter read,” Thomas says. “Now we know within 24 hours or less. We know about outages within 15 minutes, and we can ping a meter to report its status in 55 seconds. The criticality and timeliness of information is becoming more important.”
Similarly, Southern is working to integrate data from its Itron MDM system into its OMS. “Our plan is for the MDM to be the hub,” says Duane Wright, customer-service manager for the business-applications support team at Southern in Atlanta. “When a meter loses power it will send a last gasp back to the MDM system, and from there the data would go in near-real time to our OMS. Right now we are looking at writing a program to get the information out of our MDM system.”
In such models, the MDM system serves as the universal translator between various metering systems and distribution-operations systems, including OMS and asset-management. And in these models, MDM is the logical process to perform a central-hub function.
“That’s the role of MDM,” says Eric Miller, vice president of software solutions for Itron in Oakland, Calif. “To provide a single and consistent interface that minimizes back-office changes. It also involves separating out the operational data from the billing data, and sending different data to different places at different speeds.”
Not all utilities will use MDM systems in this way, however. Some might build parallel systems to manage time-sensitive operational data, such as outage and power-quality flags, outside the MDM system. So far, such a system has not been christened with a widely accepted moniker.
“We’ve been calling it an operational data manager,” says Debbie Henderson, business development executive for the energy delivery group at OSIsoft in San Leandro, Calif. “AMI is bringing back-office systems together in one picture, but the MDM systems that exist today are designed to take meter data and process it for billing—not for operational purposes. The operational data manager would take distribution-system and substation data and make it useful for the operations side of the business.”
This parallel-system model would allow real-time operational data from AMI systems to be processed in a common environment with SCADA and other distribution-automation information. Such an approach might better serve the needs of outage-management processes, which need connectivity with devices on the distribution system to occur as close to real time as possible.
“I’m not sure every operation needs to go through the MDM system,” says Raymond Kelley, director of software development and test at Elster in Raleigh, N.C. “For example, if the OMS needs to poll meters in the AMI system, it needs a rapid answer. If the OMS is based on open standards, it may not need to go through the MDM.”
Alternatively, another piece of middleware might evolve with comprehensive event-management functionality, to manage the massive amounts of data coming from smart-grid systems, and route operational and billing-related data streams according to their application and timeliness.
“This type of central component doesn’t exist yet, but we have the concept and requirements in mind,” Taylor says. “It would be an intelligent platform that sees the events that happen on the network, understands which systems needs information about those events, and then hands the data off.”
Such middleware functions—whether they are handled in MDM or some other system—might be the key to making the smart grid fulfill its potential.
“The in-between is becoming very significant,” says Ron Chebra, a senior principal consultant with KEMA in Mercerville, N.J. “Utilities have been islands of information, and we need to bring those islands together. To do that you need to manage where data traffic goes, who owns it, who needs it, and how it is used by various applications. It really is a mindset change to view metering as an extension of distribution automation and SCADA.”
One of the latest buzzwords among utility IT experts is “service-oriented architecture” (SOA). In general it refers to software systems that play well with others, using data standards and communication protocols that are open and interoperable.
As the intelligent grid evolves, SOA will be critical to ensure smart meters, automation gear, and middleware systems function well together and remain relatively future proof.
“It’s up to the vendors to develop platforms based on reasonable standards,” says Henry Bailey, utility-industry principal with SAP in Philadelphia. “That’s what the vendor community is doing right now. In the end there will be more than one standard. But using SOA, each will have the ability to adapt and integrate with different standards, so customers can pick different hardware and software vendors.”
With SOA and advanced-automation systems, even the most audacious smart-grid visions are theoretically possible. Data from metering and SCADA systems will be integrated fully with CIS, OMS, and asset-management systems, and intelligent processes will make full use of that data in restoring outages, optimizing the efficiency of assets and giving customers all the information they need to make decisions about their utility services.
“The foundation has been laid to do all this,” Bailey says. “The call centers and workforce-management systems are there. Devices are communicating in real time, and sensors and controls are enabling switching and dispatching in real time. The next step is to connect the pieces together.”
Connecting the parts and making them play nicely together will be the challenge, and it also will unleash the many opportunities of the smart grid. And as more systems go live and smart-grid functions become available, their uses become increasingly apparent. For example, when the start date for daylight-saving time moved ahead this spring, UI was able to reprogram its entire AMI network in less than 24 hours at a very small cost. Similarly the company implemented a major change in rate design in just a few hours.
While the ultimate vision for the smart grid has yet to be described in full detail, utilities have been bringing that vision to life as they’ve moved forward with deployments, one intelligent system at a time.
“We’ve been working on AMR and AMI for a lot of years,” says Wright of Southern Co. “Early on, we recognized a lot of hidden benefits that we couldn’t exactly put our hands on, and it made it difficult within the company to get buy-in to the idea that this will really happen.” As new technologies and applications have become available, however, the idea of the smart grid has caught on at utilities like Southern, and more internal groups are becoming interested in the real-world possibilities.
“Now people are coming to the table faster than we are rolling out the technology,” Wright says. “That leads me to believe we will be able to realize the benefits of the smart grid.”