TECC Group, Inc. has identified 14 U.S. investor-owned electric utilities (IOUs) as major players in research and development (R&D), with expenditures in excess of $10 million. TECC's report,...
Low-Tech vs. High-Tech AMP: The 21st Century IT Debate
failing to integrate successfully with other systems will cause costs to jump, not fall. This is the belief of PwC's Dorow.
Because AMR implementation begins at the business or business manager level, sometimes the chief information officer (CIO) is not involved until very late in the game, he says. In fact, much of Dorow's work at utilities has been discussing how to integrate meters with customer information systems and other systems that may be related.
"[AMR implementation] has been business-driven rather than technology-driven. The CIOs are then out there trying to find out how to make it happen. The earlier that the business gets the technology and the CIOs involved in doing the business case and looking at the system integration pieces, I think that gives the business a better picture of what the cost is to implement and maintain an AMR."
For example, utilities must address either integration of their AMR system with their mobile workforce management system, or make sure the radio fixed network has the collection capability of sending that information to a customer information system.
"[In addition], it becomes more of a challenge with some of the old CIS systems out there," says Dorow. "Some utility CIS systems are 10, 15, and even 20 years old, and to try to integrate it with different systems are very expensive and very risky, and can ultimately make or break an AMR implementation."
Meanwhile, executives such as Roland Schoettle, CEO at Optimal Technologies International, do not believe demand-side programs can be successful without two-way communication between customer and utility.
He believes the problem of looking at the markets for large commercial and industrial customers is that 35 percent of the market already has been covered. But the rest of the market has not been covered by any kind of decent metering initiative, he says.
The residential markets still take roughly 36 percent of the power used and have very heavy swings, while small commercial customers have been missed, he says.
In fact, ICF Consulting in a May report estimates that approximately $4 billion of savings in electric system operation costs could be achieved annually if 50 percent of customers were given price signals in peak periods.
"You have a meter that gives you information-but who is going to want that information? Not many people. At that point, the metering initiatives mostly become advanced billing systems, helping to reduce utility costs but not really helping the responsiveness in the market place that needs to be there. These demand-side initiatives are going to fail unless you can create some kind of automatic response system based off the information coming from those meters," according to Schoettle.
Of course, a major impediment to the development of price-responsiveness in demand is the existence of rate caps and fixed default service rates. In its May report, ICF Consulting suggests public utility commissions should explore how all, or only targeted, customers can be transitioned into dynamic pricing, without violating rate caps or significantly affecting utility distribution company revenues.
"The positive experience of Puget Sound Energy with the installation