Worlds Apart: Comparing Regional Utility Approaches to Automation

Transmission & Distribution World September 2000

By Chuck Newton, Automation Editor

A majority of the North American and International utilities that participated in the Spring 2000 survey covering substation automation trends have now established some strategy for substation automation efforts. However, a substantial difference in perception between these two geographically different groups exists when it comes to obstacles to implementing these strategies.

The 51 international utilities ranked "lack of standard protocols" as the most important obstacle, in spite of fairly strong acceptance and use of IEC's 870-5-based approach. "Lack of economic justification" followed, with "uncertain management philosophy" next. Among the 69 participating North American utilities, "benefits not outweighing the costs" was the most important obstacle. "Lack of funding" was next, followed by "not enough skilled internal staff."

These are fairly important differences. It is no wonder global corporations addressing this market cannot take a single worldwide-solution approach, since the needs and working environments of utilities are approached quite differently based on location - at least in the context of North America versus international regions.

Continuing with some of the key differences between the two groups, spending estimates differ on a scale of 15 to 1 (international to North America) for the level of planned spending on new substation programs, in favor of the international community. For retrofit programs, the ratio of spending is not quite as strong (9 to 1) but is still impressive.

One of the underlying reasons for such a difference in spending may be found in responses to subsequent questions in the survey. For example, international utility officials are far more likely to buy from larger suppliers (28% to 7%) and from systems integrators (22% to 3%), whereas, international utilities are still more likely to bring in consultants to assist in planning their substation programs. In other words, the commitment is bigger and the funding is more significant in the rest of the world than it is in North America. More than one-half of the North American utilities indicated plans to "buy the required equipment and do their own integration."

This approach seems to fly in the face of later responses that indicated that utilities are quickly approaching the time when they will have to outsource a variety of related services, such as training, commissioning and testing, and IED configuration support.

Also, it appears that North American utilities are slower to move to data-warehousing technologies than are their international counterparts. One-third of international utilities already use data-warehousing techniques, while less than half that percentage of North American utilities do.

Another partial explanation for the discrepancy may be the amounts and types of substation data being brought back to the control center. International utilities are likely to bring back more types of data on a continuous basis than are their North American counterparts. Plans in both regional groups call for more relay data, harmonics information and equipment temperature data being transmitted.

Another key to understanding the substantial differences in plans for substation automation may be found in the stage-setting levels. Here, international utilities might be further ahead by virtue that they have made more and broader investments in smart RTUs. Such RTUs are in place in 60% of international utilities, compared with 38% in North American utilities. Plans call for North American utilities to catch up over the next five years.

Today, North American utilities are likely to restrict substation data brought in only through supervisory control and data acquisition (SCADA) or energy management systems (EMS) centers (49%, compared with 35% for the international community). North Americans also are more likely to communicate with feeder IEDs and load control systems, while the international community is more likely to send substation data to trouble call management systems and regional control systems.

Plans across the world's utilities call for automated substations to communicate with more varieties of systems in the not-so-distant future, including distribution management systems, AM/FM/GIS, trouble call management and protection engineering desktop systems.

How will these discrepancies in substation automation tactics and strategies converge over the next few years? The answer lies in whether electric-utility deregulation becomes more of a national-level mandate in the United States and Canada, just as it has in other parts of the world. This has made the biggest difference, because resulting "utilities" or energy entities know exactly where they stand. In North America, deregulation has become a tedious, drawn-out and perhaps inequitable process with little regard for the ultimate benefits of the smaller electricity user. With all eyes on profits, little heed has been paid to the need for infrastructure spending in this extended interim of uncertainty over deregulation.