BG&E: Don't underestimate MDMS challenge

Phil Carson | Jun 03, 2011

 

Here's a snapshot of what the deployment of one million smart meters that collect 15-minute interval data would require from your team. It's a daunting picture that gives meaning to the phrase "meter data deluge," the topic of yesterday's Intelligent Utility Reality webcast:

• More than 96,000,000 meter reads per day
• 10,000 missing meter reads per day (assuming 99 percent success)
• More than 2,000 interval meter installations per day
• More than 1,000 customer move-ins, move-outs per day
• 20 meter failures per day (assumes a 0.5 percent annual failure rate)

 

Add the fact that meter data management systems, or MDMS, interface with customer information systems (CIS), outage management systems (OMS), data analysis applications, field service management systems, asset management functions and customer energy use portals.

Small wonder, then, that MDMS integration can cause the "significant heartburn," according to webcast moderator Christopher Perdue, vice president, Sierra Energy Group. (You can access the webcast recording and slide deck at your convenience.)

But the nature of that integration challenge and the most valuable aspects of an MDMS will vary according to the specific utility, Perdue said.

"What's critical to one utility won't be critical to another," he said.

Thus three different utilities on the webcast had different takes on what MDMS implementation required at their organization. 

At Baltimore Gas & Electric (BG&E), which serves 1.2 million electric customers in its namesake region, the need for a two-way flow of data is driven by the need for energy conservation, real-time pricing and energy analytics, according to Rich Walker, BGE's director of IT transformation.

BGE evaluated three options: a new data head-end feeding legacy MDMS and a legacy customer information system (CIS), that new head-end feeding a new MDMS feeding a legacy CIS and a new head-end feeding new MDMS and a new CIS. It chose the third, which was the most complex and expensive, as its legacy systems were nearly two decades old and it needed a scalable, integrated system to keep up with market and regulatory changes. A $200 million U.S. Department of Energy grant eased the cost.

Of the near-simultaneous implementation of multiple new systems, Walker said: "I wouldn't recommend this for the faint of heart."

BG&E has begun its ambitious implementation schedule, partially driven by the requirements of its federal grant, which accelerates this fall and is scheduled to end in 2014.

Among the lessons learned, Walker said, many will resonate with other utilities. Those lessons involved complexity, integration, resources and organizational change.

"You cannot underestimate the complexity of replacing the heart of your utility systems," Walker said. "If you're approaching the replacement of three systems, you need to closely consider your timeline and budget."

The integration challenge can be tackled in-house, but you'll need "a small army," Walker said. Better to see what options the market can offer.

Resources and expertise in the marketplace "go hand in hand," Walker said. "There aren't that many experts in the marketplace who can do this work, so you need to form alliances with your integrator and vendor."  

Jon Pettit, the advanced metering system program manager for Oncor Electric Delivery, based in Dallas, Texas, said his transmission-and-distribution utility applies MDMS differently because it serves retail electric providers (REPs), not end-consumers.

Oncor's service territory, via 107 REPs, covers 27,000 square miles, 3.2 million electric meters and 7.5 million people. Its smart meter deployment covers the years 2008-2012 and is about half complete, Pettit said. End-customers access their energy use information via a common Smart Meter Texas Portal.

Touching on related systems, Pettit said that advanced metering infrastructure (AMI) "is a business changer. It will affect all your systems and businesses and needs executive support."

Pettit's advice, like Walker's, was necessarily thematic, as implementations vary from utility to utility.

"You lose meter readers, but how many data analysts will you need?" he asked rhetorically. "Ask your vendor: what's the upgrade path? Don't underestimate the cost of storage or upgrades to your data center."

Pettit said that when fully deployed, Oncor's AMI, MDMS and related systems will handle two to three terabytes of data per month—a Texas-sized deluge that justified all the themes sounded by yesterday's speakers.

Carolyn Creedon, project process manager for CenterPoint Energy of Texas, amplified and added to many themes noted here.

To do full justice to this complex topic, I recommend that you tap the webcast recording and slide deck at your convenience.

Phil Carson
Editor-in-chief
Intelligent Utility Daily
pcarson@energycentral.com
303-228-4757