2005 Projects of the Year Showcase Innovation

By Steven M. Brown, editor in chief, and Kathleen Davis, associate editor

Electric utilities worldwide are continually working to improve the reliability and quality of power they deliver to customers, but it’s not often that they’re honored for their efforts.

During the Keynote Session of the recently completed DistribuTECH 2006 Conference and Exhibition in Tampa, four utilities were recognized for their extraordinary achievements through Utility Automation & Engineering T&D’s Projects of the Year Awards. This marked the third year the magazine has conducted this awards program, which is designed to honor the most innovative electric power transmission and distribution technology implementations undertaken by North American electric utilities each year.

Winners of the 2005 Projects of the Year Awards were:

“- Exelon: T&D Engineering Project of the Year,

“- Xcel Energy: T&D Automation Project of the Year,

“- Duke Power: Geospatial Technology Project of the Year, and

“- Alaska Village Electric Cooperative: Automatic Meter Reading Project of the Year.

AVEC Reaches Disconnected Villages with Smart AMR

Alaska Village Electric Cooperative (AVEC) garnered Utility Automation & Engineering T&D’s AMR Project of the Year award by connecting a number of small Alaskan villages to their headquarters in Anchorage using smart metering technology.

While remotely connecting a group of villages may not seem like a technological feat in our overtly tech-laden 21st Century world, AVEC’s large-scale effort serves as a reminder of just how easy we might have it here in the lower 48. AVEC’s service area covers the largest geographical area of any electric cooperative in the world, according to the cooperative. A non-profit electric utility serving residents in 52 locations throughout rural Alaska, AVEC is owned by those it serves.

AVEC began providing electric service to rural Alaska in 1968. The cooperative’s 52 member villages span from as far north as Kivalina, to as far south as Old Harbor on Kodiak Island, and as far west as Gambell on St. Lawrence Island (within sight of Siberia), to as far east as Minto, located approximately 80 miles west of Fairbanks. Minto is the only AVEC community accessible by road. All other AVEC communities are accessible by airplane or marine vessel only. Think about that for a second. What does that mean to people in the power industry-people like us? Exactly.


Typical housing in the village of Old Harbor, Alaska. Click here to enlarge image

No grid connection. No grid. At all. AVEC utilizes wind power generation at some locations and more than 144 diesel generators at others-to villages located 200 to 600 miles from AVEC’s home office. The total population served by AVEC is only approximately 20,000 people, and the members of AVEC are from diverse cultures including Athabascan, Aleut, Inupiat, Yupik, Siberian Yupik, and Caucasian. Although the majority of the members have command of two languages, there are still many who speak only in their native dialect. The means of survival for the members of the cooperative consist of whaling, fishing (from nets to fish wheels), hunting, trapping, subsistence and private enterprise. All these cultural, social and economic factors combine to create village life.

Because of the many rural locations extending over western Alaska, each of AVEC’s 51 villages conducts an annual village meeting for the express purpose of electing a delegate to represent their community at the annual cooperative meeting held each March in Anchorage. At the Annual Meeting, the delegates discuss AVEC business, and the most recent bit of AVEC business has to do with the first phase of an automated meter reading system in the area to enhance their business operations and provide better customer service to their members (as well as cut down on dangerous winter meter-reading practices).

“Life in an Alaskan village is about as rustic and remote as it gets,” said Meera Kohler, president and CEO of AVEC. “But, that does not mean that our members do not expect and enjoy the same technology [as the rest of the U.S.].”


A winter storm drifts snow up to a rooftop in the village of Kivalina, Alaska. Click here to enlarge image

She added, “It is only logical that we should be able to access electric meters instantaneously from our office in Anchorage to diagnose outages, and to be more responsive to our members’ needs.”

Without a grid, AVEC needed a smart AMR technology that didn’t require extensive infrastructure. Enter Elster Electricity. AVEC chose Elster’s EnergyAxis System for the project in April of last year and began deploying the meters in May in five villages selected to pilot the system in 2005: Wales, Old Harbor, Kasigluk, Nunapitchuk and Teller. The EnergyAxis System in these villages features Elster’s single-phase electronic REX meter and A3 ALPHA meter collector. According to AVEC, it was the EnergyAxis System’s intelligent two-way mesh network technology that made it the most cost-effective and viable system for the project.

“Elster Electricity and our partner WESCO are excited to be working with an innovative utility such as AVEC on this unique system deployment in the rural villages of western Alaska-one of the most beautiful places in the world,” said Ronald Via, vice president of sales and marketing at Elster.

And beautiful it is: hills of white snow drifting across the landscape. But, there is danger in its beauty. The village of Wales was chosen as one of the pilot sites for Elster’s solution precisely because of its extreme weather conditions. AVEC expected that this location would provide a good test of the system’s robustness. Along with the drifting snow, Wales has a high penetration wind generation system with multiple power injection points. In fact, most villages in AVEC’s service territory can be covered with as much as 10 feet of snow in winter. This makes a walk-by/drive-by fixed network solution unsuitable for the area. (With the old system, a tunnel has to be dug in the snow to read the meter on the house.) Add to this the problem that power-line carrier technology would require infrastructure, and we come full circle back to smart meters and Elster’s EnergyAxis System.


By August 2005, approximately 650 Duke Power technicians were equipped with RF-connected ruggedized laptops and PDAs. Click here to enlarge image

According to Elster, the EnergyAxis System consists of smart meters that are self-configuring, self-healing and act as repeaters. When the meters are installed, they automatically configure themselves and determine the best communication path back to the data collector, which is also a smart meter. If network conditions change, the meters automatically find another communication route back to the collector.

“I’m very impressed with the product-its application and process,” Randy Vallee, technology and training superintendent at AVEC, told Utility Automation & Engineering T&D when contacted about the award. “I have not seen any product on the market that so easily installs and begins operation without having to be an engineer with a PhD in rocket science to get it working.”

He added, “I am in the process of changing jobs, and I have no problem in believing that the next person that takes my position will be able to step in effortlessly to operate the system. Elster truly developed an AMR system that follows the KISS [keep it simple, stupid] theory.”


Thomas Callsen stands in front of DC-in-a-Box. Taken at the Butterfield site on June 24, 2005. Click here to enlarge image

At the completion of this first phase of the project, AVEC has achieved the following results:

“- 100 percent read rate on all meters installed, giving them connection from Anchorage to every one of their customers in the five villages of the pilot program;

“- Internet billing options for customers, since the data is now readily available from the server at the home office;

“- Improved safety for local personnel, who no longer have to dig tunnels to read meters or connect/disconnect service in the winter months;

“- Wilderness aesthetics left intact, as no new infrastructure had to be introduced to the landscape.

Duke Power’s MWFM Solution Powers the Carolinas

Duke Power was early to the workforce management party, deploying their first workforce management solution back in 1997 to replace paper orders for nearly 1 million routine meter work orders annually. By 2002, however, Duke Power recognized the need to upgrade the system. The eventual results of that upgrade netted Duke Power the 2005 Geospatial Technology Project of the Year award.


Through its visitors’ center in Denver, Xcel Energy showcases the technology at the core of Utility Innovations. Click here to enlarge image

Concerned about support issues with their aging workforce management platform, Duke Power sought a more scalable, next-generation solution capable of handling a greater volume of work. Their existing solution was on an aging operating system, for both server and mobile device components, and Duke Power’s research indicated that the company and its workers could benefit from newer hardware and “user friendly” applications. Duke Power committed to implementing an integrated, truly mobile workforce management solution.

Duke Power’s goals were to:

“- Implement a scalable platform that could grow and be extended to different types of work.

“- Implement a self-service solution requiring minimal vendor services.

“- Reduce maintenance costs for an unsupported platform.

“- Reduce costs for mobile devices in the field.

“- Improve system performance and capacity.

Duke Power employed innovative approaches to vendor evaluation. All finalists were invited to a two-day, off-site workshop in November 2002. There, the vendors were asked to run through 12 scenarios, each written to reflect Duke Power’s varied business requirements. One demo, for example, involved creating and dispatching an outage event from Duke’s outage management system, routing that event through the vendor’s WFM system, and returning status and completion information.

The selection team critiqued the strictly managed 15-minute demos and compared the applications. After a lengthy review process, Duke Power signed a contract with MDSI in July 2003 to implement that company’s Advantex r7.5 solution.

Implementation of the Advantex solution proceeded smoothly; everything from contract signing to solution integration testing and rollout for all business units was accomplished in 52 weeks. The solution design phase, which involved creating screens and finalizing plans for building the interface, was completed in December 2003, and the host interfaces were implemented in the spring 2004. There was a one-month pilot in August 2004, and staged rollouts, including deployment of new rugged laptops, began in September 2004. The system went live in December 2004 on schedule.

Due to the project’s complexity, the many vendors involved, and the many employees impacted, Duke encountered several challenges including:

“- Technological challenges. Project success required high levels of vendor cooperation to design, test, and implement a system conforming to Duke Power’s requirements.

“- Project management challenges. 2004 was a very active hurricane season which presented significant deployment challenges because field personnel were busy with outage restorations. Rollout continued without impacting the hurricane response.

“- Coordination challenges with a staged, per-zone deployment. Duke Power replaced ruggedized laptops, installed new hardware, and converted existing orders to new software-all on weekends. Two or three operations centers were upgraded weekly so field technicians experienced little impact to productivity.

“- Training challenges. In-house, “just-in-time” training packages were delivered the week before deployment in each zone.

With Duke Power’s new implementation, all work orders associated with routine residential metering services, complex commercial metering services, and lighting services pass through the Advantex application. Duke Power uses three order types-meter, service, and construction-and approximately 100 job codes to manage the work. Work orders are processed from several hosts including Duke Power’s customer billing and information system (CBIS), an SPL outage management system, and a Worksuite STORMS construction work management system. To utilize the existing meter reading technology, the interface downloads orders and accepts readings from an Itron drive-by meter-reading system.

By August 2005, approximately 650 technicians in outage restoration, routine metering, complex metering, and lighting services were equipped with RF-connected ruggedized laptops and PDAs.

Since implementing this new mobile workforce management solution, Duke Power has achieved a number of benefits, including:

“- 18 percent increase in dispatcher efficiency (increased average number of technicians per dispatcher from 33 to 39);

“- 10 percent increase in host system interface throughput (more than 2 million completed orders in 12 months);

“- Estimated $250,000 savings from adding new business units and creating new forms without vendor services;

“- 13 percent unit cost savings from adding a new CIS interface with auto updates to and from field technicians.

Exelon Packs up DC-in-a-Box

Exelon’s new distribution center (DC) substation design, nicknamed “DC-in-a-Box,” has earned the top honors in the T&D Engineering category of Utility Automation & Engineering T&D’s Project of the Year by redefining the fundamental nature of an electric substation in suburbia. What began as a request for a less expensive 34-kV to 12-kV substation developed into a compartmental transformer that can be applied in virtually any setting.

What’s the difference between DC-in-a-Box and a traditional pad-mounted transformer? Well, it has the same fit (on the site), the same standards. But, this one is the Godzilla of transformers. Bigger. Bolder. With a lot more power. Pad-mounted transformers, however, were one inspiration for this concept.

“Not only a less expensive option, the “Ëœall in one’ DC-in-a-Box is easier and safer to maintain, more environmentally and aesthetically appealing than conventional substation designs and simpler to site and build,” said Carl Segneri, vice president of engineering and system performance for Exelon Business Services.

Exelon is one major participant in the DC-in-a-Box project. Others include: Cooper Power Systems (transformer, regulator, and recloser manufacturer), Pauwels Transformers (transformer manufacturer), MJ Electric (substation construction work) and Patrick Engineering (site specific drawings and related work orders).

“We are extremely proud of the team effort between Cooper Power Systems, Pauwels Transformers, and ComEd that went into making the DC-in-a-Box a reality,” Segneri added.

In 2005, Exelon livened the first three DC-in-a-Box sites in the world. The heart of the design is a 9375 kVA compartmental transformer with a solid dielectric vacuum recloser mounted in the low voltage compartment. The recloser’s controller doubles as the SCADA point and RTU for alarm contacts. Separate 1àƒËœ URD regulators are used if voltage regulation is required.

The DC-in-a-Box has the exact same thermal ratings as a traditional 9375 kVA transformer. According to Exelon, this is the first liquid filled transformer in the industry to achieve this rating with less than 1,319 gallons of oil. (Keeping under 1,320 gallons avoids the need for spill containment.)

“We were breaking all of the rules,” said Thomas Callsen, a consulting engineer with ComEd/Exelon. “We didn’t know what the end product would look like. But, we are ecstatic with the results.”

DC-in-a-Box offers a number of public benefits, not the least of which deals with aesthetics. A compact box is much more “pretty” than a large, fenced-in substation. And, DC-in-a-Box doesn’t need clearances or fences. There are no bare wires, and it is safe for kids to play around, according to Exelon.

Additionally, when trying to acquire property for a new substation, the most common phrase heard is “not in my backyard.” Previously, ComEd’s only offering was the traditional chain-link-fenced substation topped with barbed wire. In many cases, the property owners and/or zoning boards were not interested. The DC-in-a-Box offered an unobtrusive design that encouraged property owners to continue discussions with the utility. The completely enclosed, fenceless design has been a deciding factor in obtaining an easement for future substation sites. It also allowed Exelon to locate one site on a permitted railroad ROW.

Capacity planning departments (those boys who site substations) could see this as a less-expensive alternative to a full-blown substation. And, being, enclosed, DC-in-a-Box eliminates nearly all wildlife issues. The sealed-up conduits make it less prone to wildlife outages.

Additionally, the DC-in-a-Box has been designed to meet the exact same safety standards as the transformer in a residential subdivision or schoolyard. Each door is locked with a high security padlock, secured with a penta-head bolt, and passes pry bar/wire probe tests-ANSI C57.12.28. The tank wall temperatures are no greater than any other liquid filled transformer.

Exelon says that it has already received inquiries from utilities in five states. And, the DOE’s Office of Electricity Delivery and Energy Reliability recommended the DC-in-a-Box technology to Entergy for consideration in rebuilding after hurricane Katrina. They have three in service now, two upcoming for 2006 and seven identified for 2007.

“The innovative design of DC-in-a-Box provides engineers with a completely new alternative to conventional substation design that is both versatile and economically viable,” stated John Costello, ComEd’s executive vice president and chief operating officer.

Additional benefits of DC-in-a-Box include:

“- Safety: An “external maintenance compartment” has relocated all the gauges, valves and switches needed for routine operation and maintenance to a separate compartment. This allows the worker to take samples, purge the nitrogen blanket and read the various gauges without being exposed to any high voltage.

“- Plug-and-play technology: All gauges and relays are pre-wired at the factories using a common wiring diagram. The only relay wiring at the site involves hooking up the amphenol connectors.

“- Modular components: Individual components can be rearranged to fit the needs of each site.

“- Minor assembly required: The majority of the work is preparation and civil work. Once finished, DC-in-a-Box can be up in two weeks from the day it’s put on the pad to the day it’s livened.

Callsen added, “We relied on experts who knew what they were doing, and we’re very proud of the final package.”

On top of all this, Exelon’s DC-in-a-Box can be painted one of 50 colors. Have a fabric swatch you want to match? Come on down.

Collaboration Results in Innovation at Xcel Energy

The efforts of the 2005 T&D Automation Project of the Year winner go beyond what would typically be defined as “T&D Automation.” Xcel Energy’s Utility Innovations initiative is a broad-ranging effort with a goal of dramatically advancing the way power and service is delivered to customers’ homes and businesses. Utility Innovations has interconnected the world’s top technology firms in a unique partnership where knowledge is pooled and the whole is much greater than just the sum of its parts.

The results-both to-date and anticipated-from this initiative are impressive, but more impressive still is the collaborative effort between Xcel and the vendors involved, and the willingness of Xcel and its partners to share the results of their work with the public and other interested utility companies. It was this spirit of collaboration and altruism that set Xcel apart from other nominated projects in this year’s awards program and what garnered them the T&D Automation Project of the Year award.

In January 2004, Xcel Energy and its five leading technology partners-IBM, Indus, Itron, Mercury and SPL WorldGroup-began the Utility Innovations initiative by collaborating to develop nine business improvement projects for field operations automation, customer support and asset optimization.

IBM provided broad-based technology and software solutions, project management and system integration. Indus provided Indus Asset Suite, a work management and supply chain system and Indus Service Suite, which provides resource optimization, scheduling and mobility solutions. Itron provided meters and meter reading automation in Xcel Energy South, as well as software applications in meter data management, bulling and asset management areas. Mercury provided IT Governance Center software that monitors IT demand and optimizes related spending to improve business performance and drive competitive advantage. SPL WorldGroup provided outrage management (OMS) and distribution management (DMS) systems that improve outage response and restoration time, operational efficiency and safety precautions for utility workers and the public.

From July 2004 to October 2004, teams from Xcel Energy and partner companies oversaw the deployment of the Utility Innovations project in Arvada, Colorado, which presented the typical challenges of electrical distribution-5,500 electricity customer accounts, 600 distribution transformers, and portions of 17 feeders from three substations.

Utility Innovations was evaluated on three initiatives. Asset Management and Operations (AMO) focused on improving the utilization of distribution assets, reducing the total cost of asset ownership and improving reliability of the distribution system.

Workflow Optimization was designed to make field operations more efficient. This was achieved through the use of existing mobile technologies to improve design, resource scheduling, stores and construction activities. The intended outcome was to make field operations near real-time, mobile, automated and paperless. With Workflow Optimization, designers were able to complete designs and estimates in their first field visit, and construction crews were able to optimize resources by having the right equipment and materials, better designs and a ready job site.

Finally, Stakeholder Communications provided dashboards and portals targeted to a range of audiences and purposes. The dashboards were intended to enable executives and managers to view decision-making and historical data at any time, tailored to their needs. The portals provided a single location to manage work processes across multiple transactional systems. They also provided managed and controlled access to functions within the transaction applications to occasional, casual or external users.

From the pilot project in Arvada, Xcel Energy was able to extrapolate potential benefits estimated at $39 million per year, assuming full implementation of all Utility Innovations 2004 projects.

“Xcel Energy already has realized financial savings in 2005 with the initial implementation of a UI workforce optimization initiative,” said outgoing Utility Innovations executive director Corey Hessen. “It’s the strength of these kind of results that has lead to the creation of Utility Innovations as an Xcel Energy program that seeks new solutions for higher operational performance.”

Utility Innovations was presented to the public in May 2005 with the opening of Xcel Energy’s Visitor Center at its Denver location to highlight the results of the 2004 projects. The center is open to interested parties-including other utilities-to learn more about the Utility Innovations program.

Xcel Energy brought together its technology partners, who often compete against each other, to illustrate the ideal model for aligning IT with the business to help improve efficiency. Many new technologies that Utility Innovations incorporates are typically deployed in isolation from one another. Xcel Energy challenged its technology providers to achieve new synergies through integration that takes the value of the component systems well beyond their individual capabilities. Xcel Energy is expecting these innovations to save millions of dollars in the years ahead while also fostering a new spirit of creativity in the company. Xcel Energy is ardent about sharing the results of the initiative on an ongoing basis, providing valuable information and perspective to support other similar efforts to meet critical, common challenges facing the utility industry.

“Utility Innovations is proving that truly successful innovation can be achieved through collaboration in a utility environment,” said Xcel Energy vice president and chief information officer Ray Gogel.

“The program is putting research and development into the business model of the utility industry. And that is creating opportunities for improved reliability, customer satisfaction and other value propositions for our customers.”à¢®à¢®

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The Clarion Energy Content Team is made up of editors from various publications, including POWERGRID International, Power Engineering, Renewable Energy World, Hydro Review, Smart Energy International, and Power Engineering International. Contact the content lead for this publication at Jennifer.Runyon@ClarionEvents.com.

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