Improving service reliability in the deregulated environment

Improving service reliability in the deregulated environment

Hahn Tram and Larry Engelken
Convergent Group
6399 South Fiddler's Green Circle, Suite 600
Englewood, CO 80111-4915

Meet today's distribution utility challenge
Utility deregulation and competition, along with increasing customer demand, have forced distribution utilities to improve service quality while trying to cut costs. The utilities are pressed on all sides: internal business pressure due to competition, more stress on the bulk power system due to energy trading, higher customer demands of power and power quality, and greater regulatory and public scrutiny. Utilities have to respond to these pressures in a proactive manner and rethink their approach to improving service reliability.

Internal Business Pressure
To achieve customer differentiation and branding that their energy service affiliates can leverage, many corporate parents are calling upon their distribution companies to improve customer service "at all costs." Some have self-imposed pressure by promising state utility commissions specific levels of reliability improvements to gain the commissions' approval for their mergers and acquisitions. Scottish Power's pending acquisition of PacifiCorp is such an example. Some have promised no rate increases for a number of years, resulting in reductions of capital investment and operational costs. To add revenue opportunities, some utilities are offering programs like wire-warranty or power monitoring services, which add complications to day-to-day distribution operations.

Stress in the Bulk Power Supply
Competition and deregulation have put American utility reliability on a downward trend according to a recent EPRI study, "Electricity Technology Roadmap." Generation capacity investments have gone overseas for better rates of return, resulting in lower generation reserves nationwide. Increase in energy trading, resulting in transmission transactions with a faster pace over longer distances, has put greater stress on operations of the bulk power transmission system. On the other hand, deployment of new engineering technologies is also delayed due to a lack of financial returns.

Higher Customer Demands
Consumers today have more and more computers and other electronic appliances that are more sensitive to small power disturbances such as voltage sag and surges. Furthermore, utilities have to deal with the varied cost of energy service delivery to different service areas and the disparities among different types of customers in their perceived value of service reliability and power quality.

Greater Regulatory and Public Scrutiny
Distribution utilities are seeing the effects of deregulation. Governments and the public are more leery of degraded utility service caused by open competition and demand more reliability and service quality reports than ever. Local distribution companies take the blame for service interruptions regardless of the cause. Many states have set performance targets for distribution utilities, ranging from a cap on customerinterruption minutes to the maximum wait time before customer calls are answered. State regulation requires utilities to reimburse ratepayers and pay other penalties when their performance falls short of those targets.

Take the total business approach to reliability improvements
In response to the pressures and challenges in today's business environment, energy delivery utilities must take a proactive and total business approach to improving service reliability. Such an approach involves more than the conventional distribution system planning, engineering, and network operations and control. It requires engineering the business process and network improvement strategies together. It requires utilizing the utility's information, people, and network assets in a synergistic manner. It means in addition to planning and engineering the electric network more effectively, the utility will have to better communicate with the customers and public, as well as execute business processes in all areas together.

Communication with Customers and the Public
Perception is everything. A recent survey of overall customer satisfaction among utilities by J.D. Power and Associates indicates that 40 percent of the satisfaction comes from the utility's image and only 17 percent of the satisfaction is a result of reliability and power quality. Much of the image is built on how the utility communicates with customers. For example, customers associate how much the utility is on top of its operations with how well it keeps them up to date on outage statuses and restoration efforts during storm or other major outages and on reliability improvement measures afterwards.

Most utilities have recognized this need to improve public perception and have stepped up efforts to enhance communications with customers and the public. However, too many of these efforts are ineffective due to a lack of timely and accurate information available to the utility organizations responsible for public communication. While utilities attempt to improve customer facing with blended media technologies like Intranet Web pages and interactive voice response, they still suffer from difficulties in assimilating data from various sources within the company to provide meaningful information. They need to provide information in a timely manner and in a form the public can appreciate. For example, customers care about problems and improvement projects in geographic areas like towns and neighborhoods, not by circuits and substations. Utilities need to adapt suitable analytical engines behind their customer relationship management (CRM) initiatives. These engines and their underlying data model ought to be geospatially oriented (Tram, Engleken, and Gay, 1999).

Coordinated Planning and Management of Business Processes and Resources
Adding capital dollars for upgrading network facilities and equipment may be a solution to solving system reliability problems, but it must not be the only option. There are a number of possible ways to reduce the duration of outages. For example:

Add network automation, monitoring, and control capabilities so the utility knows about network problems or potential network problems sooner and resolves them automatically. This involves conventional network protection engineering, Supervisory Control and Data Acquisition (SCADA), Distribution Automation, Substation Automation, etc.
Provide better intelligence and decision support tools to system operators and dispatchers so they can diagnose and take corrective actions quicker and faster. This involves, for instance, trouble-call entry and analysis, outage prediction, emergency switching formulation, etc.
Improve the efficiency of field resources by directing the right crew with the right replacement parts to the right place the first time, so travel and repair times are reduced. This involves, for instance, mobile dispatch and combining field resources from different functional groups such as service, substation, and construction, for emergency response.

There are also alternatives for reducing the frequency of outages. For example:

Reinforce the distribution network and upgrade network facilities to increase the capacity and flexibility of the network, reduces outages due to system overloads. This involves both conventional and modern methods for distribution system planning and reliability engineering.
Improve inspection and maintenance of network equipment, implementing transformer load management, online equipment performance monitors, etc., to reduce failure rates of network equipment.
Increase the vegetation management effort to reduce the number of outages caused by trees. This involves keeping track of where problem areas are, as well as when and where trees have or have not been trimmed.

While every utility probably has programs in place to do each of the measures listed above already, most utilities need an information system and process in place to coordinate the planning and execution of these programs (Tram, 1999.) For example, to reduce the average customer interruption duration to a targeted level, would it be more cost effective to add network automation or mobile workforce management? Or would the utility really need a combination of the two measures, one in certain parts of the service territory and the other in the rest?

Integrated Network Resource Planning
Even for the traditional distribution system planning and engineering functions, utilities need to look at the adequacy of the applications used and the availability of data to support them. So, utilities will fix the right thing where the improvement will bring the greatest reliability value and devise the most economic solution for the improvement.

Operations and control applications such as SCADA and DMS must provide the operational data needed for planning and engineering and have the ability to follow through with the optimal engineering designs through day-to-day operations. The planning and engineering applications must be able to model new engineering technologies, most notably Distributed Generation (DG), and consider them as alternative resources to network enhancements. DG has been installed by industrial customers as a peak-shaving device to reduce the electricity demand charges or as a backup generator in case of outages on the utility network. Conversely, distribution utilities or energy service providers can also strategically place DG on their network to reduce network capacity requirements or provide differentiated services to key customers with improved reliability.

Rethink the is strategy
While all utilities have reliability improvement programs in some shape or form, few have the IS framework and applications to allow them to respond to the business, engineering, and public/regulatory pressures effectively. Utilities need to rethink there is strategy to support the total business approach to reliability so they can plan and coordinate all the reliability improvement efforts efficiently.

Validate the IS Architectural Design
To support the total business approach to reliability discussed above, utilities need an IS architecture that provides an open integration framework to leverage and support multiple technologies and applications for energy delivery (Figure 1).

Figure 1. Leveraging multiple Energy Delivery Resource Planning technologies to
improve service reliability and internal and external communications.

The functional overlaps of these information technologies represent integration points that can be leveraged to deliver the total reliability solution. For example:

The integration of an Outage Management System (OMS) with Mobile Workforce Management (MWM) and real-time systems like SCADA will reduce outage duration and collect data that is important to distribution system planning and engineering.
A Distribution Management System (DMS) will provide the operational data needed by network analysis and optimization of a Distribution Planning System (DPS) to develop an operationally flexible distribution system.
The data interfaces between OMS and DPS with a Work Management System(WMS) will help the utility track the progress of reliability improvement projects.
The graphical work design application that links a Geospatial Information System (GIS) and WMS will help the utility maintain the asset data accurately and timely for engineering and operations.
The integrated data model that supports the energy delivery applications will also facilitate communications with the customers and public, and position the utility for e-business with the necessary communication and analysis capability.

Instead of one closely integrated system similar to the Enterprise Resource Planning (ERP) model, the authors found that an open integration framework that can support and leverage multiple technologies and applications is much more effective for energy delivery. The integration of best-of-class technology allows the utility to more quickly and cost effectively respond to changing business requirements and technology advances as required for reliability improvements in today's utility environment.

Evaluate the Suitability of Applications
Utilities need to review whether they have the energy delivery applications for today's needs. The impact of DG is a prime example. From the planning and engineering perspective, while DG has been in use for years, recent announcements of small-scale microturbines and fuel cells, sometimes referred to as "micro-DG," could dramatically increase the market size for applications of less than 100 kW. That would require careful planning and optimization as DG changes the optimal network configuration and affects feeder load balancing and protection. The increasing number and spatial diversity of DG require new information system applications with a geospatial-oriented database structure.

From the distribution operation and outage restoration perspective, in a conventional network model for outage management for instance, the substation is considered the only source of power. If there is connectivity from the substation to a customer, the customer is assumed to have power. This may not always be true from the customer perspective because the substation may not provide enough voltage support to meet his needs. Conversely, if there is no connectivity between the substation and the customer, it is assumed that the customer has suffered a service interruption. This assumption may also be invalid. There may be a generation source on the distribution network, DG, that could be providing power to a customer disconnected from the substation. In other words, a radial distribution system will no longer be a valid assumption for OMS, and loading and voltage analysis may be needed as part of OMS.

Besides the evaluation of the analysis engines and data models, many utilities will also need to validate the implementations of the applications. For example, do compatible units used in Work Management still effectively reflect the material standards and labors of today, including new options such as DG? How useful are the outage cause codes in helping the utility plan reliability improvements? Are there compatible units and cause codes that are so seldom used that they only serve to slow down the work process?

Rethink the IS Implementation Approach
Utilities are facing business requirements that are still changing ever so rapidly. The de-regulated market is still evolving, and the regulation at the distribution level is still being debated in many states. Technologies are advancing rapidly, e.g., microturbines for DG and Internet technologies for e-commerce. Mergers and acquisitions are still happening in a fast pace. All these require utility IT organizations to be nimble and proactive to change. Utilities trying to justify and implement individual technologies will ultimately lose their effectiveness to change. Rapid implementation of best-of-class technologies in a proven flexible architectural framework becomes a critical success factor (Tram, Engleken, and Gay, 1999).

Summary
Taking a total business approach to reliability is a must for today's utilities that face pressures on all sides, from internal business pressures to public and regulatory expectations, and from stresses on the bulk power system to complications caused by DG installations. The total business approach requires the coordinated planning and execution of business processes and functions involved in the utility's system planning, engineering, operation, maintenance, and restoration of its distribution network. Just as importantly, the total business approach requires providing timely and accurate information for proactive communications with the customers and the public as part of the day-to-day operation process. The utility must rethink its energy delivery information system strategy and reevaluate its applications and their implementations to ensure that the IS can support the total business approach and allow the utility to remain nimble and proactive to coming business requirement changes.

Reference

Tram, H., 1999, "Integrating Utility IT Systems to Meet Distribution Management Needs in the Competitive Environment," Electric Light and Power, January 1999.
Tram, H.; Engelken L.; and Gay, A., 1999, "Strategy for Spatially Integrated Distribution Information Systems in Energy Delivery Utility Mergers," GITA Conference, April 1999.
Tram, H.; Engelken L. and Gay, A., 1999, "Implementation of an Information Technology Architecture for Energy Delivery Utility Mergers," DistribuTech Conference, February 1999.