EnergyBiz - January/February 2008 - (Page 49) relatively easy to explain to customers and regulators why interconnected utility problems need interconnected utility business processes. So what’s not to love about smart grids and smart metering? The problem is our failure to consistently connect technology with goals. There is, in fact, no single definition of either smart metering or smart grids. Contrary to popular opinion, smart metering does not require interval meters, nor do smart grids require demand-side management applications. Each solution is better viewed as set of technologies from which the smart utility puts together a package of serial implementations to address specific, timed, and prioritized problems. Let’s take an example: Utility X. It implements a smart metering system consisting of interval meters, two-way communication, and a meter data management application. Utility X cost-justified this approach to smart metering on the basis that: Ô Meter reads and remote connects / disconnects will reduce demands on field crews. Meter “pings” will identify “false alarms” from customers and prevent unneeded truck “rolls.” “Last gasp” notifications will more quickly identify the location and extent of outages. Interval data will help the utility appropriately size grid equipment. Interval billing will permit critical peak pricing programs that can reduce peak demand and bottlenecks. Ô Other departments, however, are questioning additional expenditures on making demand response work. They point out that most of the bottlenecks on the Utility X grid don’t result from predictable events like hot summer days with high air-conditioning demand. They result from load re-routing that occurs because the grid cannot detect and automatically recover from blink-outs related to summer storms. Utility X cannot use demand response to recover from these situations because it cannot -a situation in which utilities can provide the needed one-day notification of a critical peak period. Ô Ô Ô Ô The system functions as promised. But there’s almost no change to Utility X’s bottom line. Why? Ô Utility X has a “no layoff” policy that reduces field crew staffing only as employees resign or retire. Outages produce so many “last gasp” notifications that Utility X cannot handle the volume. The meters, it turns out, are gasping at every little blink-out. Utility X solves this problem by asking the communications provider to hold last gasps for 20 minutes and “ping” the meter at 5-minute intervals. Several no-power messages later, the communications provider forwards the outages. But by that time, customers have already called. The idea that the new system will permit replacing largerthan-needed grid equipment is going in the right direction. The problem is that much of the equipment is far from the end of its useful life. Replacing it early would not provide enough benefits to outweigh the amortization loss. Eventually, Utility X will realize savings–but not soon. Utility X’s demand response pilot program earned rave reviews. But fewer than one percent of its residential customers signed up for long-term demand response once the interval meters were in place at all service points. Managers are scrambling to recover from this problem, but solutions will require time and money. Ô Ô Ô Prior to its decision to implement smart metering, Utility X had most of the information it needed to predict that the plan would not produce the desired results. But the information was siloed in different departments. Those advocating smart metering did not know how to ask all the right questions or identify all the right people. Many of those with needed information did not fully understand the relationship between the information they had and the proposals on the table. And the external pressures on Utility X to “do something” produced a rush to decision. Had Utility X elicited and analyzed its information at a more deliberate pace, it might have initiated smart metering with an arrangement for load-shedding through direct control of business and residential air conditioning, plus back-up industrial load-shedding available with notifications of an hour or two. It might have continued with a campaign to encourage customers without power to call into an IVR system that solicited more information than just the single power-out notification. And it could have introduced communication with meters and interval metering gradually, one district at a time, so that field crews and still-functioning equipment could be moved to the areas without new meters. Similarly, smart grids are not necessarily the distribution version of the Christmas tree, with every new technology ornament hung on. In fact, many utilities have already made the minimum investment necessary to take advantage of business process automations that are fundamental to the smart grid concept. You may already have deployed, for instance, communicating fault indicators, sectionalizers and tie points, and SCADA controls down the feeders. For you, it may be the next logical step to move to fault location, isolation and service restoration, which uses the on-going capital investments utilities are already making to automate fault response. There’s no doubt that tomorrow’s smart utility will have a smart grid and smart metering. There’s also no doubt that the combination of issues at some utilities require an immediate move to robust, multi-featured smart grid and smart metering programs. But listen in on the conversations in your hallways and at utility conferences. Many managers see alternatives to the large-scale, near-term smart grid and smart metering programs their utilities are currently considering. Consider their proposals carefully. Smartness isn’t about jumping on the bandwagon. It’s about driving it where you want to go. ThOughT LE aDErship – spOnsOrED By Or acLE uTiLiTiEs www.energycentral.com E n E rgyB i z 49 http://www.energycentral.com
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