As a member of power industry consultant KEMA’s intelligent networks & communications practice, Ron Chebra often meets with utility executives to explain the impact a smart metering or smart-grid initiative will have on the company’s customer information, billing and other back-office systems.
He usually kicks off the meeting with a brief video clip from “I Love Lucy” called “The Candy Factory.”
In it, Lucy and Ethel have been hired to hand-wrap individual pieces of candy as pieces trundle down an electric conveyor belt. At first the candy is delivered at a reasonable pace. But then the conveyor belt picks up speed, reaching the point where the two simply cannot wrap the candies fast enough. At that point all hell breaks loose and the hilarity ensues.
“I like to show that during my presentation,” Chebra says. “My point, of course, is that a utility can’t suddenly go from gathering meter data once a month to gathering it every hour without making significant changes to its back office. I usually see a lot of nodding heads and nervous smiles.”
Suffice to say most power industry executives—especially those looking to institute an advanced metering infrastructure (AMI) program— have a pretty good understanding of what’s going to be coming down that conveyor belt.
The multi-million dollar question is: Will the utility’s customer information service (CIS) be able to handle a large-scale smart-meter deployment, and if not, can it be modified? Or will a full-scale CIS replacement be necessary and if so, how much will it cost?
While AMI and smart-grid pilot programs generate the headlines, most back-office system modifications or change-outs are still on the back burner.
Jerry Melcher, a consultant with EnerNex Corp., describes the typical AMI implementation as a two-step process. “First you have the infrastructure build out, with the new meters and the communication network to the back office put in place,” he says. “Then comes the back-end systems, including a meter data management (MDM) system, which will take all the billing determinants needed to construct the charges in accordance with the tariff.”
According to a December 2008 FERC report, advanced-metering penetration in the United States is just under 5 percent. That means U.S. AMI programs still are in the pilot or early build-out stage. Utilities in the midst of a major smart-meter deployment are years away from completion. As a result, even if dynamic rates are in place, it will be years before the U.S. power industry can clearly demonstrate the impact a large-scale AMI program will have on a utility’s CIS and billing systems.
“Most utilities have ignored the downstream impact to customer information systems,” says Allan Schurr, vice president, strategy and development, with IBM’s global energy and utilities industry practice. “Many have begun their AMI programs without developing plans for the CIS, partly because in many instances the dynamic pricing models in their territories aren’t firm yet. It could be years before time-of-use (TOU) rates are standardized and implemented in the U.S.”
That’s a good thing too because, as Chebra’s presentation demonstrates, most utility customer information and billing systems are ill-equipped to handle an AMI build-out.
The typical CIS is designed to accept monthly residential consumption data taken manually by a meter reader. It validates the data, applies the customer’s rate structure, places the data on billing forms or delivers it to a separate billing function, and adds taxes and other fees. The bill is printed and mailed, and payments are logged in and credited to the account. The customer’s billing history is archived so it can be accessed by the utility’s call center if and when necessary.
An AMI program will wreak havoc because it will deliver use data on either an hourly or quarter-hour basis. Instead of taking a single reading, subtracting the previous month’s reading and billing the difference, there will be from 24 to 96 readings per day, times roughly 30 days, resulting in anywhere from 720 to 2,880 separate readings per month. Divide that total into three different time-of-use rate slots, and it’s easy to see why most existing CIS and billing systems will need some sort of upgrade.
Is it better to replace or modify the CIS? For a given utility, the answer depends on what’s in place right now.
According to Guerry Waters, vice president, industry strategy and marketing with Oracle Corp., roughly 45 percent of U.S. electric utilities employ a legacy CIS custom-built by a vendor and the company’s IT staff. Few if any of these systems will be able to handle TOU data without modification. The other 55 percent, he says, have upgraded to an “out-of-the-box” CIS product that might, or might not, be able to fulfill all AMI requirements.
“Some of the distinguishing features of a CIS handling smart metering is the ability to calculate and bill complex rates—such as time of use, critical-peak pricing, direct pricing, hedge pricing, real-time pricing, etc.—and to send and receive event signals to and from the smart-metering environment,” Waters says.
In most cases, systems will be modified with a “bolt-on” MDM system that will gather the use data, place it in a batch format, and deliver it to the CIS. “Utilities aren’t looking to swap out their CIS. Most expect to put an additional layer of processing in front of it,” says Rich Huntley, energy conservation and demand-response practice leader for Vertex Business Solutions. “An MDM system coupled with a billing engine can aggregate the data into final, bill-ready information and then hand it over to the CIS.”
“It’s very situational,” adds Frank Hyde, principal business consultant at Ventyx Inc. “If the existing system is 10 or more years old, that can be a lifetime in computer years. With our CIS, we’ve made modifications that permit the user to add layers of logic that keep the overall system in tact. You can surgically go in and add another set of codes to deal with the complex rate structures.”
Some utilities, however, already are choosing a complete back-office system overhaul, though not solely for an AMI deployment. Such is the case at Jackson, Mich.-based Consumers Energy, which replaced a 30-year-old-plus CIS built in-house with an SAP for Utilities solution in 2008.
Consumers Energy is a charter member of the SAP AMI Lighthouse Council, an industry group SAP created in 2007 to integrate the end-to-end processes between smart meters and back-end systems. Consumers Energy is testing the first release of SAP’s AMI-enabling software in a prototype environment. The utility plans to begin deploying about 5,000 smart meters this spring for a smart-metering pilot program.
The SAP solution aims to accomplish two things. It integrates all of the utility’s back-office systems, and provides an enterprise-wide gateway to the smart meter that will support a multi-million smart-meter deployment scheduled to begin in 2011.
“You can buy a robust MDM with AMI capabilities to augment your CIS or buy a ‘thin MDM’ and add AMI capabilities to your CIS,” says Tom Harmes, Consumers’ AMI IT integration manager. “With SAP we’ve replaced more than 100 legacy applications. Now we’re working to add the AMI functions.”
The utility decided to upgrade its CIS long before it decided to implement AMI, but the CIS is integral to the program. This summer the utility is planning a pilot that will test the AMI network’s ability to support minimum smart-grid functions, collect energy usage data for upcoming programs and capture operational metrics for full deployment planning.
“We wanted to optimize the functions we already had with SAP, while the SAP solution also will allow us to implement our AMI functions going forward,” Harmes says. “For example, for residential customers, we’ll be able to collect hourly usage data one to three times a day, totaling 720 hourly-interval meter reads per month; remotely turn the power on; monitor and report on outages; and help customers monitor their energy usage and take advantage of new energy pricing options that are being proposed.”
While some utilities might have put back-office issues on the back burner for now, customer-facing systems ultimately must accommodate the changes wrought by smart-metering infrastructure. According to Maureen Coveney, SAP’s senior industry director, the Lighthouse Council’s efforts demonstrate that some utilities already are putting customer systems front and center in their smart-grid strategies.
“Consumers Energy and other Lighthouse Council members are helping us take our CIS processes and essentially AMI-enable them,” she says. “By working together we’re determining which business process will most benefit from process-ready meter data, how they intend to interact with meter data, and how to handle handoffs between the systems.”
Though most AMI and smart-grid projects in the United States are either on the drawing board or just beginning to launch, Coveney says utilities should be assessing their downstream systems now, rather than later.
“If a utility is in the midst of a smart-meter program and it hasn’t begun implementing the back office to accommodate it, it’s going to be rushing to do so at the end,” she says. “If they wait, they’re going to find themselves behind the eight ball.”