Four Utilities Honored with 2003 Projects of the Year Awards

By Steve Brown, Senior Associate Editor, Kathleen Davis, Associate Editor, and Patricia Irwin, Contributing Editor

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The Utility Automation & Engineering T&D Projects of the Year Awards are designed to honor the most innovative electric power transmission and distribution technology implementations and engineering projects undertaken by North American electric utilities each year. At a point in history when investment in T&D is sorely lacking, the work being done by this year’s award winners becomes all the more impressive.

Winners of the 2003 Projects of the Year Awards are:

  • PPL Electric Utilities: Automatic Meter Reading Project of the Year
  • Kansas City Power & Light: T&D Automation Project of the Year
  • PECO Energy: T&D Engineering Project of the Year
  • Orlando Utilities Commission: Geospatial Technologies Project of the Year

PPL Breaks New Ground with Largest Electric AMR Project in U.S.

On January 20, 2004, PPL Electric Utilities, a regulated electricity distribution subsidiary of PPL Corporation headquartered in Allentown, PA, accepted Utility Automation & Engineering T&D’s AMR Project of the Year award for their extensive fixed network automated meter reading (AMR) project.

In January 2000, PPL Electric Utilities decided to move forward with an AMR project after an extensive review of the business case. Three major factors in the company’s decision were increasing costs, retail market deregulation and the unbundling of certain services.

“The need to maintain and improve service quality was particularly significant for us,” stated John Yanek, former director of the AMR project for PPL Electric Utilities. “The first phase was to create the best metering automation strategy to meet our business needs.”


PPL Electric Utilities’ Lee Lakatosh works on exchanging one of the meters for the AMR project.
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According to Michael Wiebe, president of MW Consulting and a leader on the PPL Electric Utilities project, the metering automation strategy involved a rigorous process to create a long term view of business needs and what advantages AMR could bring to that equation.

Yanek and Wiebe both pointed out that the report assessed the relative merits of various automation tactics and concluded that a fixed network AMR system would create the best blend of benefits to meet PPL Electric Utilities’ needs. The plan chosen was an ambitious one: deploying a fixed network AMR system that is thought to be the largest all electric AMR systems of its type in the country with 1.3 million meters when completed. DCSI is providing 99.5 percent of the end points (all single-phase, network and poly-phase meters), while Comverge is providing 6,000 end points for the largest commercial and industrial customers.

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The strategy was to develop and implement the AMR plan as quickly as prudently possible in order to maximize the benefits, Yanek stated. PPL Electric Utilities, supported by MW Consulting, developed an AMR project plan involving four phases:

  • Phase 1 focused on developing the best overall meter reading automation strategy to meet present and projected 15-year needs.
  • Phase 2 involved developing a detailed fixed network business case while
  • Phase 3 focused on procurement, and
  • Phase 4 covered system implementation.

Each phase involved considerable planning, according to Yanek.

“A fixed network AMR project is an enormous undertaking in many ways,” he stated. “Unlike ‘walk-by’ or ‘drive-by’ AMR, which merely address the monthly billing process, a fixed network touches almost every group in PPL Electric Utilities.

“As a result, there were numerous meetings and briefings with all stakeholders including affected employees,” he added. “The project was subjected to numerous rigorous formal reviews and ‘gut checks’ before the authorization was provided by the board of directors to enter into contract negotiations. The review process was repeated before the contracts were signed.”

The project used an iterative analysis process founded on PPL Electric Utilities’ understanding of its present processes, and a joint PPL –MW Consulting team was formed.

Giving credit to his executive leadership, the AMR project team and the processes established with vendors, Yanek was able to reduce the original 36-month implementation schedule to 29 months.

“Once we convinced management that the projected benefits were real and realizable, they wanted the system deployed as fast as possible,” commented Yanek. “When the instruction to expedite deployment was issued, the whole team responded to the challenge and developed an expediting program to leverage the existing plans, processes and tools.”

Nearing the end of the implementation process (in mid-January about 1.1 million of the 1.3 million meters had been installed), PPL Electric Utilities is beginning to realize benefits for customers and the business, including labor reductions for billing reads, special reads, power outage management, call center and meter inspections.

PPL Electric Utilities’ billing read rate is over 99.5 percent using the new AMR system, a significant improvement over the manual process (with a read rate of about 94 percent, which fluctuated with the weather). Wiebe and Yanek believe that the deployment has proven the validity of several strategic benefits that were not included in the case, as well.

The most innovative parts of the project, Yanek said, have been employee involvement and risk management.

“Involving all of the stakeholders helped to keep us on schedule and ensured everyone was abreast of developments and supportive of any changes,” he said. “We got employees to literally sign up for their portions of the project and commit to realizing the benefits. For example, we had finance involved from the start and got them to approve the financial model developed by MW Consulting, which allowed us to rapidly create ‘what if’ financial scenarios and present the model’s results to finance for their analysis. We negotiated a Memorandum of Understanding with the IBEW local that allowed us to have a mixed team of meter readers and contract staff to perform the meter exchange work and both groups were held to performance standards.”

The second area where PPL Electric Utilities broke new ground involved a risk management plan, which was developed with the support of MW Consulting. Used to track risks and prepare contingency plans throughout the entire effort, the plan was instrumental in enabling PPL Electric Utilities to beat the deployment schedule, according to Yanek.

Overall, now that the project implementation is wrapping up, Yanek feels like quite the proud papa, even if he has moved to a new assignment as manager of field services generation support.

“It’s one of the biggest accomplishments of my life,” Yanek commented. “I’ve been fortunate, in my 26 years in the business, to have the opportunity to do many things, work with very talented people, but this is, by far, the biggest accomplishment of my career. The credit goes to all of the dedicated people who worked long hard hours. The support we received from various work groups was outstanding. The AMR project is a result of the best teamwork I have ever seen,” he stated.

Wiebe added, “Having actually worked several of these projects and having audited several others, this is one of the best run projects—if not the best run—that I’ve seen. So, John’s got reason to be proud. All you have to do to see that is take a look at some of the metrics: the shortened schedule, for example, the functionality, the capability, the scope of the project. He’s done an overwhelmingly wonderful job of pulling this thing together.”

KCP&L Project Results in Cost-effective Automation Solution

A unique collaboration between Kansas City Power & Light (KCP&L) and Telemetric Corp. has resulted in improved operations for KCP&L and better service reliability and quality for its customers. Perhaps more importantly, KCP&L’s work has opened the door for other utilities to implement distribution automation in a cost-effective manner.

The project, which has enabled the extension of distribution automation into parts of KCP&L’s territory and allowed the inclusion of new applications that wouldn’t previously have been considered candidates for automation, was named the winner of Utility Automation & Engineering T&D’s Automation Project of the Year Award.

KCP&L and Telemetric worked with several intelligent electronic device (IED) vendors to develop an economic automation solution using public communications networks along with low-cost hardware and software.

KCP&L worked closely with Telemetric to help define their requirements for:

  • A low-cost DNP-Remote Telemetry Module (DNP-RTM) for monitoring and control of any DNP 3.0-compliant device,
  • A low-cost, self-contained capacitor control/radio device,
  • A web-based graphical user interface (GUI), and
  • A secure virtual private network link to SCADA.

KCP&L signed a contract with Telemetric in October 2001 and began working with Telemetric in March 2002 to integrate the newly developed DNP-RTM into various manufacturers’ IEDs. The devices were rolled out into KCP&L’s territory from December 2002 through May 2003.

KCP&L and Telemetric also designed a low-cost device with a self-contained radio to monitor and control capacitor banks. The device alarms for blown fuses, loss of power and low or high voltage. The first phase of installation was completed in May 2002. In addition, Telemetric introduced a web-based GUI for the RTMs and the capacitor control devices.

Through the end of August 2003, KCP&L had deployed Telemetric’s devices on the following distribution system devices:

  • 30 low-cost capacitor neutral sensing devices;
  • 10 RTMs on capacitor controls;
  • 18 RTMs on regulator controls;
  • 6 RTMs on reclosers.

Carl R. Goeckeler, P.E., and Philip H. Cosey III, were the KCP&L distribution automation engineers who led the project. Goeckeler noted that the capacitor monitoring devices have already proved their worth in the field. He also stated the devices have successfully notified KCP&L of eight problems with blown capacitor fuses plus power outages and voltage anomalies in outlying areas. He said this was done with self-contained devices that cost less than $1,000.

Goeckeler said KCP&L has placed an order for an additional 60 of the capacitor neutral sensing devices, which will effectively automate every fixed capacitor in the utility’s East and South districts by the end of 2004.

KCP&L has found success with its new automation technology in its Sugar Creek substation. At this sub which serves the City of Sugar Creek, Mo., KCP&L installed Telemetric devices in December 2002 to monitor and control the following devices: Siemens MJ-XL regulator control, Beckwith M-2001B load tap-changer control, Westinghouse ESV recloser, Turner 69-kV switch and the GE Harris concentrator that collects operating data from various devices.

The value of the Sugar Creek installation was quickly realized when a battery failure was detected at an automated transmission switch within a month of the switch being automated. A crew was able to make repairs that subsequently allowed two successful automatic switching operations ensuring power was retained to the city served by this isolation switch.

KCP&L noted additional success using this technology at a Nu-Lec automatic recloser changeover installation at the City of Baldwin, Kan., in the utility’s South district. Here KCP&L dispatchers were notified of the initial loss of service to the City of Baldwin followed by the prompt service restoration through automatic reconfiguration of reclosers.


KCP&L’s Sugar Creek substation installation uses a Telemetric T646 MicroRTU to monitor a circuit recloser.
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Both the Sugar Creek and Baldwin installations are examples of new technical applications or applications in geographic areas where KCP&L probably wouldn’t have considered automation in the past because it would have been cost-prohibitive.

Not only has the automation project enabled KCP&L to better manage its transmission and distribution systems and provide more reliable service to its customers, the project also is helping other utilities explore T&D automation in a relatively inexpensive way. This is not a proprietary system that KCP&L and Telemetric developed. At the time of KCP&L’s nomination for the Project of the Year Award, approximately 40 utilities were using Telemetric’s DNP-RTM, and that list of utilities was growing rapidly. Another 11 utilities were using the SCADA virtual network connection that was also part of this project.

KCP&L’s unique collaboration with vendors and the fact that the resultant technology is available to all utilities were major factors in KCP&L’s receiving the 2003 Project of the Year Award.

“This will help utilities experiment with distribution automation in a very scalable way,” said Bill Herdegen, KCP&L’s vice-president of distribution operations. “Before, you might have had to invest hundreds of thousands of dollars. Now, for just a thousand or two, you can get immediate experience with some DNP-compliant devices.”

“We truly hope this helps other utilities and distribution automation as a whole,” Herdegen continued. “That was one of our goals when we started the project. We feel very strongly about distribution automation at KCP&L and the success of it in the utility industry.”

Historic Feeders get an Update At PECO Energy

In the center of Philadelphia, not that far from the Liberty Bell, is a 1.4-square-mile area populated by historic homes and restaurants and powered by an equally historic electrical grid. Ducking down into a manhole will reveal a 13-kV network system, which is, in many respects, fundamentally different from the network protector systems found in other major cities. The recent system upgrade for this unique piece of the grid garnered PECO Energy the T&D Engineering Project of the Year Award from Utility Automation & Engineering T&D magazine.

The system, which serves about 7,500 customers and powers all the traffic lights and all the street lighting in the area, was designed and patented by Mr. P.H. Chase, former chief engineer of the Philadelphia Electric Company (now PECO Energy). It was installed back in the 1920s (replacing the original DC system).

Power is supplied to the area by three networks, which are each composed of three primary loop circuits. The primary can be sectionalized by automatic circuit breakers supplying a fused secondary network. Operation of the circuit breakers is controlled by a balanced current pilot wire system.

The last upgrade of the system took place in 1967, when PECO replaced the original vacuum in oil breakers with vacuum in air breakers (VCB). The original pilot wire and primary cable were re-used, and the primary voltage was converted from 2,400-V to 13,200-V.

By the mid 1990s it was clear that the system was due for another upgrade. The original switches were approaching 35 years old, and PECO had refurbished all of them at least once and many of them two or three times.


It is a tight fit and a huge improvement. New breakers for Center City’s networks increase safety and cut maintenance time in half.
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Deteriorating control wires were causing spurious tripping, which compounded another problem with the network—locating the open breaker. “We would know we had an imbalance by looking at SCADA from the substation breakers, and based on the loading we could make an intelligent guess where the problem might be. But, someone would have to go to every location on that loop circuit—up to 20 or 21 breakers—to verify that they are actually closed,” said Joseph S. Hay, engineer for underground distribution at PECO Energy Corp.

“Our network is very redundant,” he continued. “So we can lose an entire loop and still have our secondary side supported. From an operations standpoint, when a breaker opens, we had no way of knowing if three or four more breakers opened with it. (And, that has happened before.) So it became standard procedure to send a crew or two out to verify the switch position of every breaker on the circuit.”

Another problem was the lack of a visible disconnect. In the past, the vacuum bottles on the old units from the ’60s would sometimes leak, and workers would not know it until someone went down into the vault and performed a potential test. “There were occasions when we detected stray voltages, and that is a big safety concern,” Hay said.

In response, PECO doubled the required amount of switching and blocking. Anyone working on VCB would have to open the two switches on either side and then open additional breakers within the primary loop. Workers then lifted the elbows on the adjacent breakers to fully isolate the one in need of maintenance. “As you can imagine that was a big problem in the busy and crowded Center City. A place where we would have cars parked on top of manholes. So our switching and blocking operations took, literally, 24 hours,” Hay added.

Besides being time consuming, the continuous operation of the elbow terminations contributed to the loss of the watertight seals around the primary bushings and also to the general deterioration of the elbows.

To solve this problem, PECO formed a project team in 2002 to figure out what to do with the area. People from multiple departments (operations, customer response, maintenance, etc.) became involved, and 11 different models were proposed. “Internally, we had fans of the network, and we had people who would like to see a radial system. Some people wanted to go with network protectors. It ran the gamut,” said Hay.

In the end, the project team decided to keep it simple and upgrade the existing network by replacing breakers, installing new pilot wire and adding fiber optic communications.

Trayer Engineering of San Francisco, Calif., manufactured and provided the breakers for the Center City project, and also assisted PECO Energy with onsite engineering.

PECO Energy completed the first of nine loops in June 2003 at a cost of about $1 million, and the company is delighted with the results. “We are already planning to do the next two loops over the next two years. Then we will work on the adjacent circuits and expect all three networks to be completed by 2008,” added Hay.

On the completed loop, each new breaker has an electronic relay that emulates the original trip coil design and communicates with PECO’s SCADA system. When an outage occurs, line workers know exactly where to go—no more loop patrols.

Second, the new vacuum circuit breakers have a visible disconnect, greatly simplifying the work needed to isolate a breaker. (This feature reduced switching and blocking requirements by 50 percent.)

The visible opening makes it unnecessary for workers to pull the elbows from adjacent breakers for safety reasons. This eliminates wear and tear on elbows and lessens the likelihood of water infiltration, therefore extending the life of the bushings.

“We also installed new Elastimold bushings with LED lights and capacitive test ports. The advantage here is that you can stand on top of the vault and look down through grate. If you can see lights blinking on each side of the switch, you know that it is energized,” stated Hay.

The new vacuum breakers are smaller than the old oil breakers, but the cabling footprint is maintained. This freed up valuable space in some tight manholes and eliminated recabling costs.

“We recently had our first fault, which was very exciting,” Hay commented humorously. “We were actually considering inducing our own fault, but we figured we would have a hard time explaining it to our customers if something went wrong. Especially when you are dealing with 80-year-old equipment. So after we nixed that plan, within a week we had our first fault on the new loop. The guys in the operations center were very excited when they saw it light up on the screen, and they knew exactly where to dispatch the crews.”

Enterprise GIS Boosts Reliability for OUC

The Orlando Utilities Commission (OUC) refers to itself in its tagline as “OUC—The Reliable One,” and it’s a moniker that fits the utility well. In October 2003, PA Consulting Group named OUC the most reliable electric utility in the Southeast for the second consecutive year.

But the municipally owned water and electric utility isn’t resting on its laurels. OUC’s implementation of an enterprise geographic information system (GIS) garnered OUC the Utility Automation & Engineering T&D Geospatial Project of the Year Award for 2003 and should help the utility maintain its position as “The Reliable One” in the future.


The new enterprise GIS at the Orlando Utilities Commission allows the utility to move maps and facilities data out to field workers in a timely manner and also ensures that the maps and data will be accurate.
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In 2000, OUC realized it needed a single, centralized geodatabase to better support operations and reduce its operating costs. Prior to the recent GIS implementation, OUC supported its water and electric utility operations with a combination of CAD drawings and paper maps. The resources to manage all this disparate information were being stretched thin, and OUC made the move to implement modern GIS technology. The utility researched its options and ultimately chose ESRI’s ArcGIS and Miner & Miner’s ArcFM solution in 2000.

The GIS project kicked off in 2001 with ESRI providing software and on-site support and Miner & Miner providing software and implementation services in the form of data modeling, product implementation and integration of the GIS with OUC’s existing outage management system. MJ Harden Associates assisted with data conversion of OUC electric and water distribution facilities data. The GIS went into full production in January 2003, making the project eligible for the 2003 Projects of the Year award.

As one would imagine, the GIS implementation was not without its challenges. Beyond the technological challenges of data conversion, data migration and interface development, the implementation’s “human aspect” was also a hurdle for OUC, according to Rick Frymyer, OUC’s technical development engineer and manager of the GIS project’s electric portion.

“Several of us here at OUC have been champions of GIS for many years,” Frymyer said. “We’ve always wanted to do it, but we’re not experts in the technology. Just trying to understand what GIS is and what we wanted to do with it so we could convey our wishes to the vendors was a challenge.”

OUC felt that a “one bite at a time” approach would help ease the transition to the new GIS, and thus the implementation was divided into eight phases: project planning; system and hardware architecture and deployment; GIS software deployment; data modeling and functional analysis; database conversion and migration; GIS application and interface development; training and resource development; and ongoing system maintenance and operation.

Prior to the implementation, OUC completed a detailed electric system inventory that collected data and GPS coordinates for more than 90,000 poles, transformers, streetlights and other distribution equipment. While the level of detail devoted to the electric system inventory wouldn’t have been absolutely necessary for the GIS implementation, Frymyer noted it has made the geodatabase remarkably accurate.

Now OUC has all of its electric facilities data in one common repository; water facility data is kept in a separate single geodatabase. Frymyer said the common geodatabase system allows OUC to move maps out to field workers in a more timely manner and also ensures those maps will be accurate.

The most immediate benefit OUC has realized from the electric GIS implementation thus far has been in the area of outage management.

“We have one interface to the GIS right now, and that’s through our outage management system,” Frymyer said. By feeding its outage management system with data from the new GIS, OUC is able to provide the most current and accurate facilities data to its dispatchers and field workers.

“That’s the biggest bang for our buck today,” Frymyer said.

Frymyer said that OUC has future plans to use the GIS as a foundation for not only outage management but also work management, distribution planning and analysis, and customer information applications.

“We view this project as a foundation implementation that we can build on over the next five or six years,” he said. “Over the long run, we’ll be able to expand into other useful applications.”

After having the GIS in full production for a year, OUC has also realized the following benefits:

  • Elimination of duplicate datasets;
  • Development of a seamless GIS source to produce better, more up-to-date maps;
  • Improved access to city and county planning data;
  • Improved data sharing capabilities;
  • Increased response to changing business needs;
  • Cost savings through centralized business and data management systems;
  • Reduced effort to prepare for operational analysis; and
  • Reduced time required to search for information.

Most importantly, Frymyer said, the new GIS and the applications that can be built upon it will help the utility maintain the high standard of service OUC holds itself to.

“It allows us to serve our customers better,” Frymyer said. “Everything we do is based on our ability to make our customers’ experience the best it can be.”

Projects of the Year Judging Panel

2003 Projects of the Year Award nominees were judged by a panel of unbiased industry experts. All utilities involved in the transmission and/or distribution of electric power were eligible to enter. Nominations were judged based on the size and scope of the project, the level of innovation used, and the benefit the project provided to the utility, its customers and the power industry as a whole.

The 2003 judging panel consisted of:

  • F. Garrett Johnston is the manager of Chartwell Inc.’s AMR and Advanced Metering Research Series. He has analyzed the utility industry for Chartwell since 1998. Valued for his AMR expertise by both industry insiders and outside knowledge-seekers, he has overseen the research and production of Chartwell’s last three annual AMR reports, as well as more than 20 reports devoted to the AMR industry. Garrett earned his bachelor’s degree from James Madison University in Harrisonburg, Va., in 1993, and is pursuing his MBA in risk management/finance at Georgia State University.
  • Anil Pahwa received a B.E. (honors) degree in Electrical Engineering from Birla Institute of Technology & Science, Pilani (India), in 1975, an M.S. in Electrical Engineering from University of Maine, Orono, in 1979, and a Ph.D. in Electrical Engineering from Texas A&M University, College Station, in 1983. Presently he is Professor and Graduate Program Coordinator in the Electrical and Computer Engineering Department at Kansas State University, Manhattan, where he has worked since 1983. His research interests include distribution automation, distribution system planning and analysis, and intelligent computational methods for power systems analysis. Dr. Pahwa is a member of Eta Kappa Nu, Tau Beta Pi and ASEE. He was elected Fellow of IEEE in 2003 for contribution to power distribution system automation and restoration. He has been a member of the Advisory Committee of the DistribuTECH Conference since 1990.
  • Patricia Irwin, P.E., is an engineering consultant and technical writer. She spent the first 10 years of her career as a substation engineer at a large Eastern utility and then worked as the editor of an electric industry magazine. Her articles about the power industry have been published in dozens of magazines around the world.
  • Pam Boschee is the managing editor of Electric Light & Power magazine.
  • Steven Brown is the senior associate editor of Utility Automation & Engineering T&D magazine.
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