By Joseph Hobbs, L.S
Evidence indicates that geospatial technologies are providing a great deal of benefit to electric utilities, but measuring the value in dollars and cents remains difficult.
The technology we now refer to as geospacial IT dates back to the late 1960s when utilities began using excess computer capacity to create automated maps.
Computerized distribution operations systems have evolved from playing a supporting role as departmental solutions to serving as the foundation of the IT systems utilities depend on to manage their businesses. Despite their emerging preeminence, IT investments such as geospatial systems, outage management, field force automation, and others face greater scrutiny than ever from senior managers and shareholders clamoring for tangible benefits and quick payouts.
Unfortunately, many utilities are finding it extremely difficult to justify IT implementation costs—not because the technology is faulty, but for lack of industry-accepted metrics, guidelines and standards with which success and failure can be measured in dollars and cents.
No doubt the utility industry experienced its share of IT disappointments early on, but anecdotal evidence today indicates AM/FM/GIS and automated systems for outage management, customer service and work management are doing what they are supposed to do. But we still can’t quantify just how well. Compounding the difficulty of quantifying system value is the fact that distribution operations IT systems now affect so many aspects of utility operations that their benefits can be subtle, indirect and difficult to measure.
However, with some IT investments now hitting or exceeding the $20 million mark, the cries for financial justification will certainly win out. Large, multi-year implementations will continually have to prove themselves as they compete for a utility’s finite resources at each budget cycle.
For this reason, major utilities such as NSTAR and Baltimore Gas & Electric (BG&E) are looking squarely at the bottom line during their IT project implementations. The research conducted for this article is the first step toward a benchmarking study to be performed by KEMA Consulting and the research arm of its subsidiary, XENERGY Inc. The study’s objective is to examine how well IT projects have fulfilled expectations according to metrics that quantify the technology’s benefits.
Once Simple, Benefits Now Complex
The utility industry’s habit of investing in new technology without calculating the monetary payoff probably results from IT’s gradual evolution throughout the enterprise. Automated technology began as a relatively small expenditure that didn’t warrant careful examination by the accounting department, but it grew steadily from there.
The technology we now refer to as geospatial IT traces its roots back to 1968 when Public Service Company of Colorado decided to expend some excess computer capacity on creating an automated map. The map provided a coordinate system upon which the utility’s distribution components could be precisely located.
“Measuring the viability of an automated map was pretty simple,” said Hank Emery, president of Emery and Associates Inc., a Denver-based GIS consultant who worked on that first Public Service of Colorado automation team. “If the computerized map replaced three mapping technicians, and the map cost less than their salaries, it was worth it.”
Emery, who is credited with coining the term “automated mapping/facilities management” (AM/FM), doesn’t recall any of the early adopters putting a price tag on the operational benefits of computerized mapping, although the advantages were clearly recognized. He said that field crews immediately started saving time because they knew exactly where to go, and they no longer had to make repeated trips back to the office to get the right equipment. Such time savings directly impacted the bottom line.
“In the first decade of AM/FM development, I think the savings were so obvious, utilities didn’t bother to quantify them,” Emery said.
Throughout the 1980s, AM/FM and GIS technology quickly spread beyond facilities mapping into many of the business operations within the utility. By the early 1990s, any hope of directly equating AM/FM/GIS implementation with operational cost savings in a simple calculation was probably lost as other types of automation came on-line, making cost/benefit relationships difficult to establish. Outage management, workforce management and mobile workforce management became part of the automation lexicon, and utilities have since begun installing these modular packages extensively.
Today, geospatial IT implementation is dominated by integration of multiple systems. Projects focus on linking the AM/FM/GIS with the outage management system (OMS), customer information system (CIS), mobile workforce management, and other automated modules so they can share data and perform tasks seamlessly. Integration has the potential to increase operational efficiency and significantly reduce operating costs.
But integration also poses a great challenge to making accurate return on investment calculations. When applications are successfully integrated, it becomes more difficult to trace benefits back to any one source. Additionally, the synergies produced by parallel, multi-system implementations amplify the benefits that could be gained by implementing systems one at a time.
Despite these difficulties, utilities must examine the advantages of IT investments at every level of the enterprise and translate the benefits into dollars. If this financial justification does not occur, utility executives will likely become less willing to approve increasingly expensive automation and integration projects.
BG&E Knows What to Expect
The first step in quantifying the benefits of a new technology is to clearly define at the outset what the implementation is expected to achieve. BG&E had a head start on knowing what to expect from its AM/FM/GIS implementation, known as Atlas, which is now under way. Twenty years ago it developed the Electric Trouble Operating System (ETOS), an automated system that analyzed patterns of incoming trouble calls to pinpoint reliability problems. ETOS was an early version of today’s automated OMS and has helped BG&E provide better service.
Atlas involves automating all of the utility’s electric and gas distribution maps, an enormous task slated for completion in late 2003. BG&E plans to link a number of automated modules, including an OMS product, to the AM/FM/GIS, which also will communicate with a CIS.
“We know the value of quickly diagnosing a failure and its cause,” said Ken W. DeFontes, Jr., BG&E’s electric transmission & distribution vice president. “Our goal (with the OMS) is to immediately estimate how many customers are impacted so we can deploy crews more efficiently and give customers a better idea of when service will be restored. Atlas working together with CIS provides the electric system connectivity to support OMS.”
BG&E has compiled a list of measurements it will use to determine if these objectives are being met. But DeFontes is quick to add that benefits can be direct or indirect and can be quantitative or qualitative.
For example, Atlas will enable the utility to change the way it maintains its network. Automation will make it possible to update as-built changes to the system map almost immediately, meaning that for the first time engineers and field crews will work from the same information.
“This will directly reduce the cost of maintenance and record keeping,” DeFontes said, adding that it will also improve performance in the field and in the design departments. This relationship may be hard to trace directly since so many other factors with Atlas will also boost efficiency, but the benefits will trickle down to deliver enhanced profitability.
“The bottom line for BG&E in terms of quantitatively measuring the performance of Atlas boils down to an overall cost reduction in operations, a reduction in staff and savings on capital investment,” he said.
The capital investment savings are expected as the automated system helps BG&E engineers and technicians more accurately monitor the health of distribution systems, subsystems and individual components. The utility expects this will allow it to defer or eliminate some expenditures on new equipment.
“From a qualitative perspective, however, we will judge the value of Atlas and related systems by customer satisfaction,” he said. “We plan to periodically ask our customers how well we’re doing.”
NSTAR Measures Performance
NSTAR in Boston is also in the midst of a geospatial IT implementation and integration project that it will judge by an extremely rigorous set of performance metrics. These metrics will be applied not only to the IT components, but to every aspect of the enterprise.
NSTAR has used AM/FM/GIS technology for many years on its electric side and, in recent years, has been expanding the automation throughout the utility. Plans for the performance metrics, however, weren’t included with the original automation proposal. The metrics idea arose late last year after a well-publicized summer of outages left the utility feeling it needed more than just a change in technology.
“We’ve really internally assessed exactly where we were ” and now we are implementing corrective action plans,” said Gene Zimon, NSTAR’s senior vice president and chief information officer. “We are looking at key measures reflective of productivity and customer service, and we’ll track them across the company down to the individual.”
Many of these measurements also will reflect the performance of NSTAR’s IT systems, which are undergoing significant modifications. In addition to initiating a gas distribution GIS pilot, NSTAR is integrating its existing electric GIS with its CIS and OMS. Subsequently, an automated work management system also will link to and share data with the GIS.
“Our strategy is to position GIS as an enterprise system, so that it isn’t just an application in the drafting department but one that is open to, and used by, all parts of the company,” Zimon said.
The integration efforts will create a completely automated operating model. Every customer will be linked to the correct transformer, and each transformer will be located accurately on the engineering model, which will tie back to the operating model maintained in the OMS. The operating model will be updated from the SCADA system for off-schedule conditions. When an outage occurs, the dispatcher will have a complete onscreen picture of impacted customers, possible causes and crew status.
“There are many advantages to having full connectivity represented on the GIS, but the main benefit we anticipate will be in work management,” he said. “Our longer term plan is to enable our crews with full access to the specifications and geographic representations of our gas and electric distribution network. They will have the same information as the dispatchers.”
In this configuration, the most tangible benefits come not from the GIS, but from its integration with everything else, Zimon said. The integration will enable NSTAR to identify problems more quickly, get a crew on scene rapidly and restore power with minimal lost customer time.
“These things translate directly into better customer service and greater productivity,” he added. “We’ll measure them by customer minutes lost, number of customer interruptions and restoration times. Those are really the key performance indicators.”
NSTAR’s list won’t end there. The utility is examining every aspect of internal and external performance in preparing its measurement indices. They will go into effect, gauging the success of all departments and people, in 2002.
“This is not just a measurement program. It’s a change in the way we operate,” Zimon said. “We plan to use it constructively as a means of raising expectations for the entire company.”
Joseph Hobbs is vice president of strategic consulting services at KEMA Consulting in Englewood, Colo.