By Jim Roche, Cooper Power Systems/Cannon
While the smart grid and stimulus funding discussions have garnered significant attention during the past six months, there are utilities already reaping the benefits of their investments in smart grid technology–resulting in improvements in efficiency, productivity and their quality of service.
The substantial benefits are witnessed throughout the diverse operational departments within each utility and by the consumers they serve.
The four utilities surveyed are in varied states of deployment, and this article provides details concerning implementation strategies and methodologies, their business drivers and their observed results and benefits. Highlighted last are the future plans and opportunities available to these utilities because of their underlying anvanced metering infrastructure (AMI) investments.
Prince George Electric Cooperative
Prince George Electric Coop-erative (PGEC) provides power to more than 11,800 members in a six-county service territory via a 1,249-mile distribution network. The 70-year-old cooperative based in Waverly, Va., has long embraced enabling technology to address efficiency needs and implemented a high-bandwidth powerline carrier (PLC) AMI solution to improve service to customers.
PGEC completed its systemwide deployment in 10 months, accelerated from its 18-month work plan, deploying 1,000 meters per month using the services of Davey Resource Group (formerly SRI). The implementation also makes use of a 3G wireless network, providing IP connectivity to the utility’s substations to provide a wide-area network (WAN).
Prior to implementing AMI, the member-read cooperative estimated an average of 5 to 8 percent of its bills. This has become a thing of the past. Cash flow has also been positively influenced. As billing latency was reduced from 15 days in some cases to less than 2 days throughout. With AMI, PGEC has experienced a 2 percent reduction in energy diversion.
The AMI system also provided measurable results in customer service and operations. Since implementing AMI, the utility has benefited by a reduction in truck rolls of 65 percent for customer service complaints and 85 percent for customer-side outages because these situations can be validated now from the office. Engineering and operations personnel are using the system to target maintenance issues, tightly manage system voltage and facilitate system analysis, which has resulted in improved system reliability.
“Almost every customer service aspect of meter reading and customer billing have been improved, and the system provides us the tools to analyze the system for voltages and outages in the operations center,” said M.E. Malandro, principal engineer and manager of engineering.
The utility maintains the system with only one-fourth FTE (full-time equivalent/full-time employee, a measure of a worker’s time).
About 20 percent of PGEC’s personnel use the system regularly and quickly embraced the process changes necessary to achieve results.
The utility has begun to implement accompanying smart grid solutions for capacitor control and has plans to embark on programs for remote disconnects and upgraded demand response and load management.
Paulding-Putnam Electric Cooperative
Paulding-Putnam Electric Cooperative (PPEC) in Paulding, Ohio, serves some 13,000 member-owners throughout seven counties along the northwestern border of Ohio and northeastern border of Indiana.
Members throughout PPEC’s diverse service territory are served via 18 substations and two 12-kV metering points.
The cooperative was historically a self-read and self-billed system, relying on members to perform meter-reading functions. In 2006, the utility set about changing that to better serve membership needs.
After performing a thorough evaluation, the cooperative embarked on a PLC AMI deployment. This network was selected to facilitate communications to its remotely distributed meter population while allowing the utility to control the communications network.
PPEC desired a solution that offered speed and simplicity as well as tools to ensure overall system reliability. In conjunction with its assigned AMI team, PPEC developed a three-year project schedule to begin in 2007, though this was subsequently accelerated.
The cooperative uses Chapman Metering LLC to deploy its AMI system, setting some 200 meters a week. Nearly 70 percent of the PPEC system has been deployed to date. The cooperative uses GE MDS iNET Ethernet radio solutions to facilitate backhaul WAN communications, and the system uses MultiSpeak 3.0 interfaces to provide a real-time link between the AMI system and the co-op’s NISC iVUE customer information system (CIS)–and soon its outage management system (OMS).
Using the system, customer service representatives (CSRs) and operations personnel can quickly address billing inquiries and facilitate investigations into voltage situations and reported outages. This provides real-time answers to address members’ concerns and saves the cooperative money by reducing inefficient truck rolls. AMI allows them to effortlessly process move ins and move outs and provide energy consumption patterns. PPEC’s AMI system furnishes the toolbox to provide consumers feedback and information, which has facilitated member education. This has translated into valuable behavior modification and improved customer satisfaction.
While PPEC is focusing on completing its AMI deployment, it plans to implement advanced programs such as demand response and distribution automation as part of an overall smart grid initiative.
Nearly one-third of all PPEC employees use the system daily to facilitate their jobs.
“Our AMI system has provided the foundation for us to improve customer service and member satisfaction,” said Alan Kohart, PPEC manager of engineering and operations.
Cooke County Electric Cooperative Association
When the team at Muenster, Texas,-based Cooke County Electric Cooperative Association Inc. (CCEC) looked to control costs and improve operational efficiencies, it turned to AMI.
CCEC serves more than 15,000 meters throughout a vast service territory via 16 substations and 3,000 miles of line.
With less than five services per line mile, manual staff activities including meter reading were no longer going to cut it.
The team selected its AMI solution to meet its rural needs and because of its easy installation. This led to an accelerated rollout schedule, allowing the deployment to be completed within three years.
As with PGEC, Davey Resource Group performed the cooperative’s meter installation. This facilitated weekly field deployments of 150 meters. Backhaul communications to CCEC were accomplished by implementing a GE MDS iNET-II radio network. Back-office integrations include SEDC UPN CIS and a future OMS.
As other utilities have noted, billing latency was improved, thus payments are received sooner, improving the utility’s cash flow. CCEC estimates 10 percent of consumer complaints are resolved from the office rather than a truck, decreasing windshield time and minimizing fleet costs.
The utility’s remote-disconnect program is also paying dividends, reducing costs and educating consumers. Future prepaid metering and demand response programs will complement this education, increasing consumer empowerment.
Dialogue with consumers is important, said Jason Harrison, CCEC AMI project manager.
“The ability to read a customer’s meter and provide them with a detailed report of their electricity consumption allows us to open a new level of dialogue with our consumers,” he said.
The operations and engineering departments use the system to track momentary interruptions and sustained outages, and this data is used to accurately calculate reliability indices. Utility personnel are able to quickly determine whether reported outages are on the consumer side of the meter, facilitating improved outage response.
In addition, outage verification is performed via the system, eliminating the need to perform inefficient and sometimes ineffective call backs. These tools, combined with the AMI system’s ability to monitor voltage and existing supervisory control and data acquisition (SCADA) capabilities, allow the utility to improve its overall system reliability.
As expected, this cooperative is seeing reduced expenditures in meter-reading costs as well as comprehensive reductions in vehicle fuel and maintenance costs.
Roughly 20 percent of CCEC staff use the system regularly, and CCEC personnel did a tremendous job implementing corresponding process changes at the utility within a year of initiation.
CCEC is seeing a positive return on investment because of its savings in fleet and personnel expenses that come with improved operational efficiencies and productivity.
Maquoketa Valley Electric Cooperative
Maquoketa Valley Electric Cooperative (MVEC) is an electric cooperative serving a variety of loads throughout nine counties in eastern Iowa. Headquartered in Anamosa, the utility serves more than 16,000 meters via 3,100 miles of line and 37 distribution substations.
The utility needed an automation platform that would meet a variety of needs and seamlessly interface with its existing utility software systems.
It selected high-speed PLC technology because it presented a cost-effective method to communicate with all meters in the service territory and a solution that could grow for the future.
The system was fully deployed in 15 months, within the initial plan of 12 to 24 months. Installation was handled using internal labor according to existing maintenance territories, allowing simultaneous installation of hardware. The savvy crews changed out five meters per hour, on average. The cooperative implemented a backhaul communications system designed by Twin Cities Industrial Control, using unlicensed 5.8 GHz solutions from Airmux and 900 MHz Ethernet radios from GE MDS. Real-time MultiSpeak Web services interfaces were implemented between MVEC’s AMI master station and the co-ops’ using SEDC UPN CIS and dataVoice International OMS.
The utility has experienced numerous benefits as a result of its AMI implementation. MVEC historically had been a self-read system. The move to AMI has eliminated nearly 1,300 estimated meter readings per month and billing corrections that were previously necessary because of inaccurate member reads or data entry errors. AMI allows the distribution cooperative to match the billing period of its members to the billing period from their power suppliers. Because of the consistent read periods that the system enables, MVEC has been able to eliminate five- to 10-day billing latency, which reduced 50 percent of high- and low-billing system alerts.
MVEC’s engineering and operations personnel make extensive use of their AMI feature set. For instance, blinks are tracked and compared against faults detected by the cooperative’s Survalent Technology SCADA package to identify issues before they turn into outages. This methodology also allows the utility to focus tree-trimming efforts and other reliability improvement measures.
The utility has been able to proactively determine undersized transformers and determine adequate transformer and secondary conductor sizes when loads will be added. This same capability will allow it to easily compile an ongoing, accurate analysis of all services to determine any upgrades and downgrades that may be prudent.
Voltage monitoring is used to gather information in areas the MVEC engineering model shows to be of concern and to verify that the engineering model is correct prior to commencement of construction projects or development of long-range work plans.
The cooperative also uses real-time voltage monitoring at all regulator assets located outside of substations. The system automatically detects voltages that are out of tolerance, notifying appropriate personnel via text message, enabling proactive resolution.
In the past six months, MVEC has identified three regulator issues prior to consumer complaints, streamlining operations while improving stability and reliability of the grid and avoiding damage to members’ equipment.
The utility has seen an improvement of 15 percent in its average annual system average interruption index (SAIDI) rating since installing SCADA and AMI. In the event SCADA detects a fault, MVEC initiates pings to meters served by the feeder or phase in question to determine any outages.
This gives a head start on dispatching crews, sometimes restoring outages without a single call. The interface between AMI and OMS also allows MVEC to validate the extent of an outage as calls come in and to quickly verify restoration of all services before crews are sent to the next location.
“These tools have been especially useful in managing outages during storm conditions, and our AMI-SCADA combination has contributed to an 8 percent decline in outage duration,” said Jeremy Richert, MVEC director of engineering.
The utility also uses the information available from the system to plan for the future.
Every month it collects the monthly peak demand, the demand at the time of the distribution system peak and the demand at the time of its power provider’s peak for each meter.
This information will be used to more accurately allocate demand costs between the cooperative’s various rates for future cost-of-service studies and to assist them in future rate design.
Nearly 20 percent of cooperative employees use the system daily to handle tasks that fall within their areas of responsibility. MVEC continues to discuss load management and distribution automation tools that are available with the AMI platform.
AMI can enhance operations at utilities of all sizes, regardless of service territory or meter density.
Deployments can be facilitated by internal or external staff, and if well-managed, can be efficiently completed in a timely manner.
Multiple options for WAN communications exist, and IP backhaul solutions offer flexibility to be adequate for AMI and future applications.
To be effective, AMI systems must seamlessly integrate with a utility’s existing and future back-office solutions.
Investing in tools such as AMI can provide significant benefits to electric utilities. AMI provides avenues to improve customer service, cash flow, outage management, system modeling, voltage support, demand management and consumer satisfaction.
“The primary reason for installing an AMI system was to get timely and accurate meter reads,” Richert said, “but the secondary benefits that allow us to improve service reliability, reduce outage duration and improve the customer service experience are just as valuable.”
Wherever pertinent, statistics should be recorded to measure success of automation projects and provide direction to where future gains can be made.
This record-keeping will become even more critical for utilities that will use stimulus grants to fund their projects to meet reporting requirements.
Process changes should be tackled head-on by providing extensive training to utility staff to help eliminate the barriers and bottlenecks that can stifle transition.
It’s easy to see how AMI systems enabled improvements in efficiency, productivity and the quality of service at each of the utilities surveyed.
These deployed AMI systems have also provided the backbone for additional smart grid implementations.
“It was a good fit financially, and from a technical stand point, is loaded with benefits with lots of potential moving forward,” Malandro said.
These utilities have set themselves up for future success.
Jim Roche is the senior marketing manager for AMI solutions for Cooper Power Systems/Cannon. He received a bachelor’s of science degree in electrical engineering from Iowa State University in 1998 and has held engineering, customer service and product management positions at Cooper/Cannon for 12 years. For more information, e-mail him at firstname.lastname@example.org.