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Clarke Electric installs new control, meter systems

Published: Tuesday, Aug. 13, 2013 4:08 p.m. CDT • Updated: Tuesday, Aug. 13, 2013 4:13 p.m. CDT
OST photo by BAILEY POOLMAN These are two meters used by Clarke Electric Cooperative. The meter on the left is the former meter, and the one on the right is the new meter. The new meters have advanced capabilities, including responding faster, updating information more quickly and allowing for two-way communication.

Clarke Electric Cooperative has installed new control and meter systems for the cooperative’s members.

In 2009, Clarke Electric was awarded $2.3 million in matching funds from the U.S. Department of Energy to participate in a national demonstration project. Employees at the cooperative were able to install a new supervisory control and data acquisition (SCADA) system.

The installation of this system gave Clarke Electric the ability to then install equipment at their substations and on the distribution lines that is capable of monitoring the system and enabling remote operations. In addition, the automated metering infrastructure (AMI) system was installed leading to an overall package that, when integrated, will enter Clarke Electric into the world of “smart grid” technology.

“So, we think there’s significant benefits in that, and ultimately, as we go, hopefully we have other opportunities,” said Bill Freeman, Clarke Electric general manager.


AMI, finished early this year, is a new system of metering being introduced to consumers at Clarke Electric. The system used previously was a basic meter that would send in readings.

“But, our information was very limited,” said Jason Gibbs, Clarke Electric manager of member services. “And, we weren’t able to ... answer all their (members’) questions, I guess, if they had a high bill complaint or an outage.”

The new metering system can receive information requests and send the answer back within seconds via a power line.

“Back when you had a dial meter, you had to send someone out every month to read that meter,” said Brad Wilson, Clarke Electric manager of engineering. “At the end of every month, we (now) go out and collect that information remotely. ... It’s been a learning curve for us, and it’s something we improve on every month.”

“Improved information”

“It’s just improved information available to us to be able to answer questions a member has,” Gibbs said, “particularly regarding their usage or voltage.”

If there are any bright or dim lights, the new AMI system picks up on where the issue might be by looking at the voltage on the meter.

“We can check the voltage to the meter right away, and if it’s too low, that would be causing the lights to dim and we know we would have a problem and need to go out and fix it,” said Gibbs. “If the voltage looks good here, we can say, ‘Look, everything looks good on our side, and you need to call an electrician because you got something going on in your house.’”

The system can also show when a bill is higher than normal. For example, if a couple forgot they had company over for a few days and wondered why their energy bill was higher than normal, someone at the cooperative can find when the bill jumped. What the meter doesn’t say, though, is what happened in someone’s house to cause the jump.


The meters were rolled out by substation, which was implemented in September 2011. Since then, employees at Clarke Electric have been working to improve the system to increase the amount of readings they receive each month.

“There was this concept that this was going to be installed, and it would work flawlessly. That’s not the case,” Wilson said. “We’re getting a good read rate. I think we’re in the 80 to 90 percentile.”

Wilson said the cooperative is trying to improve the read rates to achieve 98 percent or more. He also said Clarke Electric is in the process of installing repeaters in the system, which will boost signals if the original signals aren’t making it to the cooperative.


SCADA installation was finished early this year.

“It’s a control-system software,” Wilson said. “It provides our utility with near real-time information, and it also provides us with remote control with our distribution and substation (facilities).”

The system works through two-way communication the office server and different devices, such as overcurrent protection device and switches. This allows the workers at the cooperative to control things remotely, without having to go to the problem.

“Basically, what that does is it allows us to see what’s going on at our substations, and monitor the activities, if you will,” said Freeman. “And also, in the future, we’ll be able to manage that power consumption.”

One example of managing power consumption is the load-control device, which is currently being tested. The load-control device is used during peak demand, such as summer and winter, and will control how many minutes a member’s air conditioner and hot water heater are on.

Self-healing schemes are another advantage of the SCADA system being integrated with field equipment. This means if the cooperative loses transmission to a substation, with the push of a button, or automatically, power will be restored through circuit switching in approximately two minutes, which is comparable to the past average of four hours.

The remote control also means less travel for employees, especially in bad weather, and less risk for line crews through limiting the physical process of operating switches

“I would say, as far as the SCADA system, I think we’ve had a lot of success with that,” said Wilson. “It brings value to our members through improved safety, improved reliability and efficiency.”

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