Glendale Water and Power, the municipal utility for the city of Glendale, California, is one of the first U.S utilities to connect all of its electric customers using smart grid technology and the first to integrate smart systems for two commodities: electricity and water. The company has more than 84,000 electric and nearly 33,000 water smart meters in operation. The transition to a smart system took about 3 years and was led by Glenn Steiger, Glendale’s general manager. In preparation for an update to Pike Research’s Smart Grid Technology report, I spoke to Steiger about this deployment.
Pike Research: I suspect this transition has been all consuming. When do you declare victory?
Glenn Steiger: It has certainly been fast-paced. Once we have all meters installed, we will begin a two month period of doing parallel readings to confirm operations. But we are by no means “done” at that point. There is now a foundation for several other add-ins. We’re about to start a pilot of distribution automation at one key substation that will run for about 12 months. We intend to install about 10 MW of Ice Bear Energy Storage units distributed over 2,000 sites that Glendale will own and operate. There’s PV to integrate. Lots more to do, so “victory” is not part of my vocabulary.
PR: So let’s go back to the beginning. How and when did the idea of installing a smart grid start?
GS: The idea of a smart grid came about through both necessity and because of our two Korean sister cities. We were looking at ways to increase the overall efficiency of our system, and to deal with some operational issues like outage frequency and water losses. Smart grid came to the top of long-term solutions. About the same time, two of our city councilors traveled to Korea and were impressed with what their utilities were doing using advanced electric system technology. We put a business case together in 2008. In 2009 we applied for a $20 million grant from US DOE and won. In 2010 we completed our proof of concept trials and began an 18 month installation program.
PR: What were the goals of the original business case?
GS: The business case looked at two broad categories of benefits: societal benefits, such as improving customer service and satisfaction, as well as enhancing conservation; and operational benefits such as increasing the efficiency of the distribution network plus reducing outage sizes and duration. What we did not look at and have never really tried to value was any reduction in personnel as a cost savings. Our business case had a payback period of 7 years, which we believe will now be less than 5 years with the DOE grant.
PR: Describe what the system consists of at the moment, and its communications network.
GS: It’s probably best to work from the customer interface. The home network communicates using Zigbee from the meter, in combination with an in-home device for customer interaction. The electric meters use the Itron OpenWay 900 MHz mesh system within the Network Area Network (NAN). The water meters use a different Itron system. Backhaul from the meters to the Wide Area Network (WAN) is handled by a Tropos 900 MHz RF network to communicate with the substations. This system will also be used for distribution automation. Our 13 substations connect via a Wi-Fi network and they connect back to headquarters via a fiber optic system.
PR: Whose in-home device do you use?
GS: We have a unique in-home device produced by a local company, CEIVA. The unit is basically a digital picture frame hung on a wall. It connects both to the Glendale system and in-house sensors using Zigbee and to the internet. The customer can see their meter data and control appliances within the home. When not being used, the customer simply loads whatever picture they want it to display.
PR: What was the toughest part of the whole transition?
GS: Designing and installing the IT infrastructure and enterprise software. This was by far the biggest piece of our overall effort.
PR: How do you measure success?
GS: Internally, we will be taking a careful look at our efficiency in outage management – time to restore power; customers affected; quality of customer service measured by calls received, dropped calls, time of calls. From the customer side we’ll be measuring the overall impact on use patterns and reductions. So far we are seeing a 3% real reduction in peak demand. We expect to improve water losses by 7 percent.
PR: Tell us what your customers have been telling you about smart grid so far.
GS: So far we believe our customers are overwhelmingly supportive. That’s not to say we have not had some vocal groups that were critical of the program, primarily out of concerns relating to exposure to RF signals. Recently there have been a few privacy concerns raised as well. In general, though, our customers are pretty happy. We may not have the average profile of other utilities, though. Glendale has a fairly high percentage of early adopters. In addition, a number of film studios, the Jet Propulsion Laboratory and Cal Tech are nearby. Their employees are very interested in new technology.
PR: Any thoughts on the future? What’s your crystal ball telling you?
GS: It will be a while before smart grid really begins to happen in the US- at least 5 to 10 years. Like a lot of energy programs in the country, it will be continue to be regional in the absence of any federal policy. Right now maybe two thirds of the east coast, Texas and California are where things are beginning to happen. Smart grids have been mandated for the California IOUs. I do think momentum will pick up in the next 2 to 3 years, though.
There is no question that utilities take an entirely different perspective on how their systems function and operate once they have smart grid capability. One thing we see happening is a lot more networking among utility systems. More and more systems, like EVs or appliances, will be networked in the electric grid simply because now they can be. Much of present day utility-system concepts are already becoming anachronisms.
Article by Gerry Runte, appearing courtesy the Matter Network.