Advanced Metering Infrastructure: The Rural Co-op Perspective

By Jim Roche, Cooper Power Systems/Cannon Technologies

Many of the drivers for implementing advanced metering infrastructure (AMI) are no different from initiatives put in place by successful companies throughout the globe: improving operational efficiencies, decreasing liabilities, controlling costs, optimizing the workload on personnel, increasing customer satisfaction, creating a library of actionable information, improving cash flow, etc.

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The list goes on, as does the growing list of utilities currently implementing AMI systems. Even those who installed automated meter reading (AMR) systems in the ’90s are seeing returns by investing in the latest in two-way, high-speed automation systems.

The drivers for automation in the rural areas can be extremely rewarding: reducing windshield time, reducing the costs of capturing billing data and adequately maintaining grid performance throughout diverse, and often large, service territories. This article examines four rural electric cooperatives that are in various stages of implementing AMI systems, identifying how and why they’re rolling out AMI as well as where they’re experiencing tangible results. It’s easy to see that these cooperatives have a sharp eye on the needs of today, while keeping their automation compass pointed toward the future.

Adams-Columbia Electric Cooperative

Adams-Columbia Electric Cooperative (ACEC) serves 36,000 members in portions of 12 counties in central Wisconsin, making it the largest electric cooperative in the state. Its headquarters is located in Friendship, Wis., and consumers are served from 26 substations. Traditionally, the utility had read all 34,000 meters in a one-week period, but cost and liability were becoming growing concerns. In addition, co-op managers knew they needed more information to effectively manage their distribution system and optimize their internal processes.

To respond to those needs, the utility set about deploying a high-speed power line carrier (PLC) AMI system, planning for a four-year deployment. In the third year, the co-op has deployed meters to nearly 23,000 locations, setting nearly 400 meters per week with utility labor, and are considering accelerating the rollout. While the administration of meter installation can be trying at times, ACEC feels it has better quality control and better intel from the field about any issues discovered. The co-op is using 900 MHz radio, WildBlue satellite connections, and even some DSL to provide backhaul communications to its substations. In the office, the system provides data to the co-op’s ATS customer information system (CIS) and has a real-time MultiSpeak interface to a Milsoft DisSPatch Outage Management System (OMS).

Although ACEC has not yet completed its deployment, the co-op is already capitalizing on the investment. Before AMI, the co-op rolled trucks for reported outages and found consumer-side problems were often the issue. Now meters are pinged to verify service before crews are dispatched, diminishing wasted time and costs. The AMI-OMS integration allows ACEC to efficiently verify outage restoration without tying up the dispatchers’ time as they perform call backs and other tasks. The system has also provided numerous customer service benefits. Customer service representatives (CSRs) can perform move-in and move-outs with real-time reads while the customer is on the phone, and can even pre-arrange a future time for an automated read-in/read-out. In addition, Dave Ziarnik of ACEC said, “We have not had to do an on-site energy audit at a location with an AMI meter installed. Instead, we are able to satisfy member concerns through load profiling.”

The staff at ACEC believes its AMI system is helping them educate the co-op’s customers and modify their behaviors where warranted. The cooperative estimates about 20 people (15 percent of the staff) use the system on a regular basis as part of their day-to-day activities.

North East Mississippi Electric Power Association

North East Mississippi Electric Power Association (NEMEPA) serves nearly 20,000 meters dispersed over 920 square miles in the northeastern corner of the Magnolia state. The cooperative is headquartered in Oxford, Miss., and serves members from 13 substations. The utility previously used contractors to read its meters but realized the need to offer customers choices, such as selectable billing days, time-of-use rates, budget-billing options, prepaid metering, etc., that simply couldn’t be facilitated via manual reads. In addition, the utility felt it was not in control, that service work was often reactionary vs. preventative or predictive. The cooperative decided to act, investigating AMI systems that could address a variety of needs and handle the challenges of accessing meters in both the city and in the distant countryside. As Keith Hayward of NEMEPA explained, “We needed a system with robust information available from the meter, speed to obtain this information, and an easy-to-use, complete software solution to pull it together.”


More effectively managing system losses, distribution voltage, load factor, power factor, and protection devices are all possible with robust AMI platforms.
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Originally planning to deploy a PLC AMI system over the course of two years, the co-op chose to use a contractor to install the meters and accelerate the project by a year. Chapman Metering has been installing roughly 500 meters per week, and the system is more than 75 percent deployed. The cooperative is using 900 MHz Ethernet radios to provide bulk communications to its substations and is interfacing the AMI system to a Daffron CIS and ultimately its dataVoice International OMS.

While they are newcomers to the system, the utility’s CSRs and service departments have begun using the system for read-in/read-outs, remote disconnects, blinking light reports, and other tasks. The engineering department is preparing to use automation for voltage and load monitoring, a robust theft detection program, and integrated outage management. They also plan to use the system to better track and manage system reliability and power quality. Load management is likely to come in the future.

RushShelby Energy

RushShelby Energy is a 15,000-meter rural electric cooperative in east central Indiana, lying between Indianapolis and Cincinnati. The utility serves its members from 14 substations and seven metering points, receiving power from Hoosier Energy as well as Duke Power. RushShelby was staff-read and faced similar issues to other cooperatives, such as often rolling trucks for high-bill complaints and trying to better manage system voltage and reliability. In addition, the co-op was faced with rising costs to read its meters and a general need for better information.

As many other rural utilities have, RushShelby selected a PLC system, as that technology best fit its territory and offered the ability to perform AMI and SCADA on the same platform. The utility required easy-to-use software and easy-to-install hardware. RushShelby, too, accelerated its rollout, now shooting for around two years, vs. the original three-year deployment schedule. The utility is simultaneously rolling out a robust fiber network to its substations, facilitating data backhaul for both AMI and SCADA information. The AMI system is linked to the cooperative’s NISC iVUE CIS and OMS platforms.

The utility’s CSR agents are quickly making use of the system, investigating complaints and processing read-in/read-outs in mere seconds and eliminating the need to roll service trucks, which saves time and money. Chris Chastain, RushShelby’s vice president of engineering, stated that “Having an actual graph that shows usage is very valuable when dealing with a high-bill complaint of a consumer.”

In addition, the engineering department is using the system for voltage monitoring and is beginning to use it to assist in transformer sizing and identifying issues on the distribution system. Dispatchers are using the system for more efficient outage management, verifying restoration without the callbacks that were occasionally necessary in the past. The AMI modules even provide the time, date and duration of outage events, which can be quite useful. With the vast amount of data from its AMI modules, the cooperative plans to perform detailed circuit analysis and enhance its system modeling accuracy.

“We will start to realize improved reliability of our distribution system because of the tools available to us in our AMI system,” Chastain said.

Lane Electric Cooperative

Lane Electric Cooperative, located in Eugene, Ore., is one of 10 electric utilities serving consumers in Lane County, bordered on the west by the Pacific Ocean and on the east by the Cascade Mountains. The cooperative provides service to 12,700 meters throughout a 2,600-square-mile service territory via 12 substations. Lane Electric had used contract meter readers but faced challenges due to an inconsistent work force, high turnover, reading inaccuracies, and inclement weather which resulted in inconsistent billing periods. The cooperative was also striving to improve customer service and manage outages with greater efficiency. Lane Electric considered AMI to be a necessary tool to operate the cooperative, no different than a line truck or billing system. After diligent planning and a thorough evaluation of various AMI technologies, this co-op, like many others, selected a PLC solution.

Lane Electric outsourced the installation for the majority of the AMI meters, while cooperative staff focused on hard-to-access locations or sites requiring meter base repairs. Despite a vast service territory, Lane Electric managed to deploy 30 to 40 meters per day per installer, finishing the full deployment in 18 months. Roughly 900 remote disconnect devices also were installed. Lane Electric chose DSL for most of its substations, while relying on ISDN for the remaining two.

The utility has already improved its billing latency (the period of time from meter read to payment received) by five days and anticipates greater improvement, which will improve the utility’s cash flow. CSRs at Lane Electric are using the system a great deal; about 60 percent of their work is done through the AMI system. Staff now handles billing and usage questions, tamper issues, demand questions, and loss of service investigations through the system.

As highlighted in the December 2007 issue of Utility Automation & Engineering T&D (“Remote Disconnect Programs Proving Successful for America’s Rural Utilities,” pages 40-44 or online at www.utilityautomation.com), the cooperative also makes great use of remote disconnect devices. With the AMI system and nearly 900 disconnects deployed, Dave D’Avanzo, manager of member services remarked, “We have seen a drastic reduction in the amount of time our servicemen spend in the field for re-reads, disconnects, reconnects, in-and-out reads, etc. They actually spend their time doing service work now.”

The co-op averages nearly 125 disconnects per month through the AMI system. Lane Electric finds the behavior modification of its membership very valuable, and as the staff has gotten proficient with the tools, the co-op has experienced higher member satisfaction.

Lane Electric is just beginning to use the system to target distribution system issues, monitor feeder voltage and verify transformer sizing. With the system partially deployed for a portion of a year, the utility saw an improvement in line losses, adding approximately $80,000 to its operating margins. The AMI system is also linked to the co-op’s OMS via MultiSpeak 3.0 web services. This has been invaluable to the utility, allowing it to pinpoint the location and extent of an outage as well as verify restoration before crews leave a service area. Lane Electric believes it may have reduced its outage response time by 20 percent to 25 percent, with a similar improvement in outage restoration time. Prior to AMI, the cooperative called every member to verify outage restoration; with the AMI-OMS link, this verification is simple, automatic and efficient.

According to D’Avanzo, nearly 50 percent of employees are using the system on a regular basis. “We’re committed to wringing this system out to its maximum potential ” taking a pretty calculated approach to using the system to its fullest capabilities.”

The Many Benefits of AMI

As one can see, AMI can benefit many departments within a utility in numerous ways. Once a utility shifts its focus from deployment to enabling the process changes to utilize its automation platform, efficiencies abound. More effectively managing system losses, distribution voltage, load factor, power factor, and protection devices are all possible with robust AMI platforms. Utilities implementing AMI can truly begin to implement preventative and predictive maintenance procedures, while prioritizing personnel and budgets to the areas of the system that need the most attention.

RushShelby’s Chastain plans to maximize his utility’s investment in the system by improving system planning, “The uses seem limitless, being able to pinpoint trouble areas and validate construction work plans, identifying issues.”

As reliability and energy efficiency are more important today than ever before, AMI provides an automation toolbox to optimize system performance. NEMEPA’s Hayward said, “The biggest factor and benefit of AMI is the fact that it gives you control of your product. You know where it’s going, who is using it, and when it’s being used. That is something new in the electric world.”

Enhancing customer satisfaction is important. Whether those customers are member-owners, as is the case with cooperatives, or a consumer that merely flips a switch across town, service is key. ACEC’s Ziarnik noted, “In the past, we knew that the usage occurred, but did not know when, thus we did not have the confidence of the consumer. Now we can tell them exactly when the usage occurred and work with them to help them better manage their usage going forward.”

Improved reliability, controlled costs and stable rates are important for all classes of utilities, from municipal or district organizations to investor-owned utilities. AMI can play a leading role in meeting these objectives as well as the energy efficiency mandates being implemented throughout North America. As America’s utilities face the challenge of the aging and retiring workforce, automation can be used to supplement the years of knowledge and experience with real-time system performance information and to implement efficient methods to replace traditional labor-intensive processes. As D’Avanzo noted about Lane Electric, “We’ve become more efficient across the board, some areas more than others, but overall, our efficiencies have improved and our information is better because of AMI.”

As these four utilities have shown, results and benefits abound when high-speed, robust AMI is implemented utilizing a well-organized plan and systematic deployment strategy.

Jim Roche is the senior marketing manager for AMI solutions at Cooper Power Systems/Cannon Technologies. He received his BSEE from Iowa State University in 1998 and has held various engineering, customer service, and product management positions at Cannon Technologies over the last 11 years. For more information, contact him at jroche@cannontech.com.

Capgemini Extends Contract with Hydro One to Implement AMI Program

Capgemini has signed a two-year contract extension with Hydro One Networks Inc., a North American transmission and distribution electric utility, to provide smart metering services for the company’s automated metering infrastructure (AMI) program, including program management, process design, systems, integration and infrastructure management.

In 2006, Hydro One launched a four-year program to deploy 1.3 million smart meters, a smart network to connect those meters to their data centers, and new and modified applications to process time-of-use billing.

The project will employ approximately 100 Capgemini staff, including global subject matter specialists and a large team of local project delivery professionals, providing the following services to Hydro One over the four-year project lifecycle:

  • Requirements management: Subject matter specialist and project management resources to help collect, define and confirm business requirements;
  • Process design: Process analyst and project management resources to help define and document new business processes to allow the efficient replacement of current meters, and define future-state operations, including billing operations, meter operations and meter network operations;
  • Systems integration: Application development and project management services to plan and execute all systems integration;
  • Infrastructure management: Design, installation and testing of new environments for enhanced applications, including application servers, data servers and network;
  • Customer contact center: Contact center specialists to identify and estimate smart meter impacts to current customer care operations, as well as hiring and training call center staff to respond to anticipated customer needs;
  • Field services: Development of meter deployment plans and implementation schedules for teams of field service technicians, as well as development, deployment and support of enabling technologies to drive substantial process efficiencies;
  • Program management: Provision of a suite of project management services, including integration, scope, schedule, quality and risk management.
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