AMI standards face a classic chicken-and-egg dilemma. Does an electric utility need to establish functional and technical standards in order to develop an advanced metering infrastructure (AMI) program? Or must the utility develop and then implement an AMI program in order to build the functional and technical standards needed to support it?
“The whole idea of AMI standards is a pretty tricky subject,” says Mike Burns, a senior production manager with metering vendor Itron Inc. “Establishing the standards is really an evolutionary process. Certain standards are driven by adoption. First you have to see what people are doing and what works.”With the Energy Policy Act of 2005 requiring both electric utilities to institute time-based rate schedules and public utility commissions to promote AMI programs, the standards-making process is generating plenty of ink these days.
Electric utilities, regulatory bodies and trade organizations from Canada to Texas continue wrestling with standards-related issues. Utilities have implemented pilot programs and a few are in the process of actually implementing major AMI programs that will encompass entire service territories.
So how are the AMI standards needed for the smart grid build-out currently being developed?
“Right now, AMI standards are being driven by vendors,” says Guerry Waters, vice president industry strategy and marketing with Oracle Utilities, which supplies the back-office software systems in which an AMI system’s data resides. “We haven’t seen any standards consolidation yet. The vendors have created multiple proprietary standards and more are emerging. And we have to comply with all of them.”
Indeed, depending on the size and make-up of a utility’s service territory, a full AMI deployment will impact countless devices located throughout the electricity delivery chain, from in-home demand-response technologies like smart thermostats, to the sensors located on power lines, transformers and substations, all the way to the utility’s billing and other back-office systems.
What the industry needs, experts say, are functional and technical standards that establish consistency in such things as communications delivery protocols, system-wide time-stamping requirements, and the smart meter’s energy-use measurement data reading intervals at a customer site.
“AMI is really a broader picture of the smart grid,” says Ivo Steklac, global vice president at AMI supplier Elster. “AMI standards will be needed to allow a wide variety of systems, from back-office data acquisition to distribution automation devices, to talk the same language.” …Custom-built Applications
That may sound logical enough, but what electric utilities and vendors are doing right now is developing what amounts to individual, custom-built AMI applications that address the needs and regulatory requirements of their specific territories.
“Part of the problem is there’s still a lack of fundamental understanding about what an AMI program entails. Some in the industry think distribution automation is the smart grid, but that’s not true. Some think the smart grid isn’t necessary. Others say without a smart grid, we’re in trouble,” Burns says.
Granted, industry standards are beginning to emerge, albeit slowly. Two important American National Standards Institute (ANSI) communications standards, C12.19 and C12.22, are now in place and have been adopted by most utilities and AMI vendors. ANSI C12.19 standardizes the way a meter formats and stores its data for delivery to the utility, while C12.22 establishes the way the data is delivered or transmitted over a communications network.
As for the functional and technical meter standards, much of the early development work in the U.S. is occurring in California, particularly with Southern California Edison’s (SCE) SmartConnect metering program. After the California PUC directed the state’s investor-owned utilities to begin establishing advanced-metering systems, SCE asked suppliers to go beyond what were then standard advanced-meter features. Among other things, SCE asked vendors to develop a meter that measures usage by the hour instead of by the month; provides remote-service activation; employs a two-way wireless network to send usage information to its back-office systems; and base it all on an open-standards design that will assure compatibility with the future generations of smart thermostats and other home-area network (HAN) devices. In 2007, the utility conducted lab and then
field testing of the new meters to verify projected costs and benefits. In December 2007, SCE announced it had chosen Itron’s Open- Way meter and communications system to service some 5.3 million customers in what is now called the Edison SmartConnect metering program.
Under the terms of the agreement, Itron will supply 80 percent, or about 4 million of the meters, while a second still-to-be-selected meter vendor—one that’s capable of communicating via Itron’s OpenWay standards—will supply the rest. SCE intends to begin deploying the meters over a three-year period, beginning in 2009.
“With regards to open standards, one really important element centered on the interoperability of the meter and the communication system, which moves the meter data to the data aggregator (and then on to the utility’s customer information system),” explains Paul De Martini, director, Edison Smart- Connect. “We started out assuming we would select two meter designs and two communications standards. Our AMI specifications still call for more than one meter vendor, but we’ve settled on the Itron Open Way communications system.”
Among the other keys to the Open Way system is its use of the ZigBee Alliance wireless protocol for HAN devices. As a member of the alliance—a group of companies creating wireless energy management solutions that comply with the same wireless protocol—the meters will be able communicate with any ZigBee-enabled HAN device. Alliance members range from meter suppliers like Itron and Elster, to companies that provide an assortment of ZigBeeenabled home-use products, including programmable thermostats, home-energy usage displays, and electrical outlets that monitor energy consumption.
“Standardization starts with a common set of communications requirements,” Steklac says. “So the ZigBee standards are open to all alliance members. The standards provide each product developer with a way to communicate with the meter and get the information into and out of the home.”
While SCE was in the process of developing its AMI program, Texas was beginning to develop AMI standards for what is arguably the country’s first truly competitive retail electricity market. In 2005, the state legislature gave the state’s PUC and electric transmission and distribution providers the go-ahead to implement a surcharge needed to recover the cost of instituting AMI programs state-wide. The PUC and utility representatives then spent a year working with meter vendors to develop the necessary AMI standards, while also keeping an eye on AMI developments in California, other parts of the U.S. and Canada. “We really liked the open architecture standards presented by vendors like Itron and Elster,” explains Christine Wright, a policy analyst with the Texas PUC. “We knew we needed standards in place for both the meter’s functionality and the data communications format. And we believed the open approach would be especially applicable to a competitive market like ours.”
In 2007, the PUC published its AMI standards, which are now driving AMI programs at each of the state’s four major transmission and distribution providers—Houston-based CenterPoint Energy, Dallas-based Oncor, Fort Worth-based Texas New Mexico Power Co. (TNMP) and Corpus Christi-based AEP Texas. The standards call for, among other things, the use of the ANSI C12.19 and C12.22 protocols, remote-meter reading, remote connect/disconnect, time stamping, 15-minute data reads, and communication protocols for in-home devices. “When we looked at the competitive market designs and open standards California and Canada were developing, we could see where the industry was headed,” Wright says. “So we feel our rule is cutting edge, especially with the HAN standards, 15-minute data-reading interval, and the ANSI requirements. Sure, our requirements could change in the future, but at some point you have to put a stake in the ground.”
In May 2008, CenterPoint announced it too had chosen the Itron OpenWay architecture and, pending approval from the PUC, also announced its intention to begin deploying some two million Itron meters in 2009. The other three electricity providers are expected to announce vendor selections this year as well, possibly by the end of the third quarter. One key to the selection process, says Don Cortez, Center- Point vice president of regulated operations technology, was the meter’s use of the ZigBee wireless protocol and the fact that DTE Energy (2.6 million electric meters) and San Diego Gas & Electric (2.3 million meters) recently agreed to similar contracts with Itron.
“We look at it from the standpoint of the customer. If you’re a company that sells HAN products, in total you’re looking at roughly 12 million potential customers,” he says. “That means if I’m a consumer, there will be a greater choice of in-home products that interface with my meter. At the end of the day, that’s what drives value out of the meter. The meters allow us to deliver new services and products to the consumer.” Texas’ AMI initiative also is unique in that it actually involves two related smart-grid programs. In addition to the AMI program, a second initiative will create a repository that will accept round-the-clock time-of-use data from all four electricity providers. The new meters will create the time-of-use data, Cortez explains, while the repository will help the state’s 100 retail electricity providers (REPs) put it to work. The repository will be accessible to customers, who can review their energy use and requirements on-line, and the REPs, which will use the data to tailor their offerings to fit the customer’s energy requirements. Putting the AMI standards in place to get the repository program up and running—there’s no projected completion date yet—is critical to moving the state’s retail electricity markets to the next level.
“We’re working with all the state’s utilities and delivery companies to standardize the data repository so the REPs can go in via an Internet portal and get the use data they need,” Cortez says. “The repository will be owned by, and operated by, the four major electricity providers. Right now we’re being guided by the PUC staff and soliciting information from the REPs. But everyone wants to get the meter and repository programs underway.”
Charlotte, N.C.-based Duke Energy is taking a somewhat similar approach to AMI with its Indiana affiliate, though it believes AMI communications standards should be IP-based throughout a utility’s distribution network.
“We’d like to see an entirely IP-based network, starting at the meter. Itron and other vendors offer a good AMI solution, but if you want to put a line sensor near a transformer and bring the data back through their network, you have to have an interface that provides entry to it. That’s why we would favor an IP-based solution,” explains Kevin Spainhour, Duke’s strategic planning manager. “Of course, that would make the meter more of a commodity and that may not be a good thing for the meter manufacturers.” Duke Energy Indiana announced in May its intent to install smart meters on some 800,000 homes and businesses that will, at least initially, provide the utility with remote meter-reading capabilities only. However, the new meters are part of what Duke calls a five-year smart-grid initiative that eventually will include HAN devices and sensors throughout the distribution system, all of which will communicate with each other through a unified computer network.
Though he wouldn’t reveal which meter vendors the utility is considering—the proposal is still before the Indiana Utility Regulatory Commission—Spainhour says the AMI standards-making process still has a long way to go.
“For example, we’ve heard a lot about the open ZigBee communication standard, but from our perspective that’s not an open communications standard. We’d like to see all the devices, both the meter and the in-home devices, IP-based,” he says, “ZigBee isn’t. It’s a proprietary radio communications protocol and all the HAN devices have to communicate on that protocol.” True enough, but it’s early in the game and many within the industry say utilities have to bite the bullet and start somewhere. “Itron’s Open Way uses the ZigBee standards and that’s what’s going to be used by SCE. And now (CenterPoint) in Texas is going to use it as well. Everybody wants the HAN standards to be future proof but these utilities have gambled to speed things up,” says Edmund P. Finamore, president of smart-grid consulting firm ValuTech Solutions. “So, right now ZigBee appears to be the leader. You also have the Home- Plug Powerline Alliance and the Z-Wave Alliance, though they don’t seem to be as far along.”
With much of the early attention focused on metering and HAN technologies, experts say it’s easy to overlook the way an AMI roll-out will impact a utility’s back-office systems. Functional and technical standards will be needed to determine, for example, which system actually will send a signal to a HAN device and which systems will receive, process and pass along the information that’s sent back. “Implementing the meter-data management system is going to be a lot of work. It’s as complex as the meter installation,” says SCE’s De Martini. “Of our project’s $1.25 billion capital expenditure budget, we estimate we’ll spend $250 million alone on IT development and integration. It’s going to take a major effort to make all this equipment work as a system. We’re about a year into it and we expect that part of the project to be completed in 2011.”
San Mateo, Calif. -based eMeter is providing the meter-data management system that will serve as the repository for the meter and event data needed to support SCE’s customer billing, energy information and utility operations. IBM Corp. is serving as the system integrator, managing the development and integration of the network management and meter-data management systems.
“It’s in this area of an AMI project that costly mistakes can, and probably will, be made,” says Ali Vojdani, CEO of UISOL, a consulting firm that specializes in utility business integration services. “How, for example, do you leverage the data being exchanged between the automated meter reading and the outage- management system? Exactly what information should go to the meter, which then communicates with the in-home thermostat? You have new devices and applications that will change the way you interact with the customer, which will impact your outage-management processes. The communications between all these functions have to be mapped out,” he says. A customer-information system, Vojdani says, has at least 70 interfaces, and each must be mapped. The telecommunication industry’s TeleManagement Forum (TM Forum) has developed an enhanced telecommunication operations map called eTOM that serves as a reference model for telecommunications industry operations.
“It provides a comprehensive process breakdown of how the industry works end-to-end, including the interfaces between the different pieces of that industry,” he says. “The utility industry needs the same type of standardized process framework. That would help utility’s minimize AMI integration costs across the electricity value chain. That would reduce costs to all stakeholders in the industry. We as an industry have to understand the importance of process integration, which goes beyond data integration.”
Absent a strong government directive, however, utilities currently have little choice but to work with vendors and at least begin developing AMI standards on their own. And that’s tough to do, because there are a lot of bases to cover and no two utilities have exactly the same requirements.
“To have common industry standards, you need to have a common mission,” Finamore says. “But not everybody is on the same page with regards to what a smart meter needs to accomplish. Right now we’re seeing utilities implementing automated meter reading (AMR), AMI and smart-meter programs.”
Stronger input from the federal government is needed, Burns says, to gain support for further smart-grid investments. The Energy Independence and Security Act, he says, is too vague in calling for smart-grid device interoperability and leaves it to the National Institute of Standards and Technology (NIST) to coordinate development of information-management protocols and standards. “What the industry really needs is high-level guidance,” says Burns. “Right now it’s a utility-by-utility battle ground. As vendors, we try to understand the utility’s needs on case-by-case basis. We have to determine why they want to employ AMI and then try to help them do it. There are at least 15 different sets of regulatory issues based on the region or utility, so we need a national policy on how to modernize the grid and move all the utilities in the same direction. This is a cat-herding exercise sometimes.”
Indeed, consider the situation in New York. In 2006, the New York Public Service Commission (NYPSC) put out a notice asking electric utilities to submit comprehensive AMI development and deployment plans by the first quarter of 2007. After reviewing the plans, the commission determined that “utilities do not have a consistent understanding of what physical and/or functional characteristics an AMI system should include.” As a result, the commission sponsored a two-day seminar last April in which representatives of the utilities, meter and other technology vendors discussed potential ways to establish consistent AMI system standards, state-wide. As of August, the commission has yet to announce its next step.
“We’re still reviewing the information that was presented,” says Spokesperson Anne Dalton. “All I can say at this point is stay tuned.”