April 1998

For a number of years, Georgia Power has been faced with competition for large commercial and industrial customers. Georgia state public utility regulations have permitted those customers to choose the utility from which they purchase electrical power. Thus when a large, well known company decided to locate a major data processing center in the Atlanta area, Georgia Power needed to provide the highest level of service at a competitive price.

This particular situation presented some issues well beyond those normally encountered when locating a large load such as the data processing center. These issues were:

• Due to the importance of the data being processed, Georgia Power’s customer needed a redundant bulk power supply to ensure continuous operation. The customer required:
  – in normal operation, half of the 7.5 MVA load would be carried by each of the two feeders.
  – two different bulk feeders with automatic transfer.
  – two power transformers. The full operating capacity of the data center would have a connected load of 7.5 MVA. Thus to meet customer requirements, Georgia Power would  have to  provide two (2) 10 MVA transformers.

• The site location provided a limited area to locate the 10 MVA transformers and any switchgear that may be required. It was decided that a substation located at the facility would be too unsightly, too costly, and require too much real estate.
  
• The location, in a commercial office park, required that the two feeders being used continue past the location of the data center to serve other loads. This requirement necessitated that the protection scheme would need to (1) isolate a failed transformer from the data center and other down-line transformers, (2) isolate downline faults from the data center, and (3) provide three-phase protection and operation.

Georgia Power initially began to design a system using their standard air insulated fused pad-mounted switchgear with an automatic source transfer package. They quickly determined that to meet most of the requirements needed, they would have to use four pieces of fused pad-mounted sectionalizing switchgear, and one automatic transfer cabinet. Thus a total of five pieces of equipment with required redundant cable runs and 18 sets of cable terminations. The system was expensive, required more real estate than was available, and would have been a very complex arrangement for operations. This design also did not meet all of their customer’s requirements, specifically splitting the 7.5 MVA load between the two sources.

Understanding Georgia Power’s focus on customer satisfaction and keeping costs at a minimum, Cooper Power Systems provided a team to work on a solution with Georgia Power consisting of the local Sales Engineer, Apparatus Engineer, and the Kyle Products Marketing and Engineering Staff. The Cooper PST-9 Pad-Mounted Source Transfer was first considered.

The PST-9 (Pad-Mounted Source Transfer) switchgear, with Vacuum Fault Interrupters (VFI) utilizes stored energy, motor operator, vacuum fault interrupters to provide the normally open and normally closed switching for an automatic source transfer. In this configuration one vacuum interrupter is in the closed position with open springs charged and the other vacuum interrupter is in the open position with closing springs charged. With a loss of source voltage, the electronic control system senses the loss of voltage and issues an open signal to the closed mechanism and then a close signal to the open mechanism. This operation provides the transfer of load through the switch from one incoming source feeder to the other. The PST-9 uses electronically controlled vacuum fault interrupters (VFI’s) to protect two load taps for down line faults.

Cooper’s standard PST-9 could provide an automatic source transfer with three-phase tap protection on the two load side taps; but just like Georgia Power’s initial system design, the standard PST-9 would still require two extra pieces of pad-mounted gear to continue the feeders and isolate them in the event of a down-line fault. Nor could the requirement of having the load divided on each of the distribution feeders during normal operation be met with this design. For the unique requirements that Georgia Power required to satisfy all elements of their customer’s request, a modification was needed. Georgia Power required a more creative solution.

To meet the need, Cooper Power Systems’ Kyle Switchgear Products developed the Pad-mounted Tap Transfer (PTT-9) package. The PTT-9 differs from the standard PST-9 by providing the source transfer on the load side of the pad-mounted switchgear as opposed to the source side. The load side utilizes the quick-charge, motor-operated vacuum interrupter, and the source side uses the one-shot vacuum fault interrupter (VFI). This unique solution was possible due to the fact that the motor-operated, stored-energy mechanism that is used in the Kyle PST’s is a full-rated, three-phase fault interrupter. Fault protection for the data center is accomplished by incorporating the Kyle Electronic Trip control with the Source Transfer Control. (See Figure 1)

The installed configuration uses two PTT-9’s versus five. The number of cable terminations was reduced to eight, and the number of cable runs required was also substantially reduced. The PTT-9 was the most economical solution that met all the requirements made by the Georgia Power customer as well as all of the operating parameters for the Georgia Power system.

• The PTT-9 design allows for a redundant bulk power design utilizing two source feeders.
  
• An automatic transfer of power is initiated when one distribution source is lost.
  
• Load is split between the redundant transformers at all times of operation.
  
• Customer load is divided equally between two distribution feeder sources during normal operations. The PTT-9 configuration provides the extra benefit of automatically switching only half of the load during an automatic transfer, minimizing the impact of the switching on other customers.

• Required space was kept to a minimum by only two pieces of switchgear being necessary as opposed to five in the other system configurations.

• Loads past the data center on each feeder could be served and isolated if a fault condition occurred past the data center by the source side VFI’s and would isolate the data center from the rest of the loads on the feed-ers by providing fault isolation at the data center.

• Three-phase transformer and feeder protection was provided.

• Low installed cost was maintained.

By teaming up to serve the customer, Georgia Power and Cooper Power Systems were able to find a creative solution that met all of their customer’s requirements, keeping customer satisfaction the priority. Additionally, Georgia Power was able to supply a high degree of reliability at a competitive price in a very competitive market.

Those of us who live high in the Sierra Nevada Mountains are on intimate terms with Mother Nature. Not only do we get to enjoy her beauty every day, we also get to sample her caprices: snow, wind, cold; snow, wind; snow, snow, and more snow. Truckee is like that. At 6000 to 8000 ft. above sea level, it is a year-round top three contestant for the coldest spot in the lower 48. As for snow, well that’s our middle name and in a way is how we got our start.

Horace Greeley’s exhortation to "Go west young man, go west!" may have started it all. Moses Schallenberger, as a member of the first pioneers to take wagons over the Sierra Nevadas at Donner Summit, the Stephens-Towsend-Murphy party of 1844, was the first albeit temporary resident of what is now Truckee. Seems as though Moses got to feeling a mite bad on his way over the mountains and decided a short stay in the vicinity would do his health good. For this he spent three long months alone in a cabin in the winter of 1844-45 before being rescued.

He was followed a few years later by the ill-fated Donner party. This unfortunate group was late in arriving for the summit crossing and got caught by an early October storm that left two feet of snow to contend with. A decision was made to quarter at present day Truckee for the winter. Unfortunately the snows didn’t relent until more than twenty-two feet had fallen. Many in the party weren’t as fortunate as Moses Schallenberger and paid for their stay with their lives.

The Truckee of today is a far cry from the isolated alpine location traversed by those pioneers, the founders of the Emigrant Trail. Sitting astride Interstate 80 and the old Central Pacific railroad, the country’s first transcontinental railroad, the Truckee of today is home to over 10,000 hardy souls who enjoy nature and all that she presents. It is also a center for the outdoor recreation industry and the northern gateway to Lake Tahoe.

The Truckee-Donner Public Utility District serves the community at 12.47 kV from four substations and a separate metering point. Like similar utilities throughout the country, we own our distribution system but rely on the local investor owned utility for the 60 kV and 115 kV transmission facilities. Our growth, nearly 90% of which is residential by number of customers, is a healthy 3-4% per year.

Like every other California utility, we are aware of the industry’s impending deregulation. However, we addressed this opportunity in a slightly different fashion by jumping on the Federal Energy Regulatory Commission 888 bandwagon, a regulation sometimes known as Transmission or Wholesale Deregulation. FERC 888 gave us the opportunity to shop for our power. There was one little fly in the ointment, however: we would have to have real-time metering of our power usage at each of the four substations where we accessed the transmission system.

What drove the project was Truckee-Donner’s ability to send out RFP’s for purchased power, provided that we were able to monitor all substations and metering points in real-time. We provide this information to a 24 hour dispatch facility, the Northern California Power Agency in Roseville. They in turn schedule our power delivery.

In order to achieve this we would need a SCADA system. The question was: Would this be economical?

A little analysis made the decision easy, a slam dunk, a no brainer as they say. Installing a SCADA system would pay for itself within two months. The real question then became how do we best accomplish this.

Truckee-Donner uses Cooper reclosers with F4C controls in all of its substations. In addition, a majority of the circuits are equipped with single-phase voltage regulators. Some of these are Cooper units and some were furnished by other manufacturers. There is the usual collection of switches and instrument transformers. We wanted a no muss – no fuss – no bother type of installation, preferably something we could install and service ourselves. We also didn’t want to mess with interfacing each and every information point. At the same time we needed to keep the user interface simple, something we could all understand and use.

We elected to use direct digital communications between our reclosers, regulators, and the SCADA system. Cooper’s F4C’s are ideally suited for this task. They use the 2179 Protocol developed by Pacific Gas & Electric and licensed to Cooper for direct digital interface through a fiber optic serial communications interface board. The recloser controls were not the problem; the regulators were. Fortunately the folks at Cooper developed a Control Replacement Assembly (CRA) that interfaced with other regulator controls. This control, the CRA-CL5A, uses the same protocol as the recloser control and was also equipped with fiber optic serial communications capabilities. Both the F4C and CL5A share a fiber optic loop as the connection to the outside world through the SCADA systems supplier’s serial interface.

The F4C and the CRA-CL5A provide all the real-time voltage and current information we need to assess the operational state of our system. There was no need to provide separate CT and PT interfaces, no need to provide matching transducers or RTUs. This was one of the major advantages of using these controls to interface our system.

Translating 2179 to the SCADA system supplier’s native language was one of the key challenges that we faced in implementing this project. We needed to apply the K.I.S.S. principle: Keep It Simple Steve. With help from Cooper and our SCADA system supplier, Quindar Products Limited, we finally settled on the use of a database translation table, a software device that took each Cooper station, feeder and device data point and translated it to Quindar’s database location.Truckee, in addition to being blessed with some of Mother Nature’s finest cold weather, is also blessed with one main street. There are little or no alternate routes available for our service vehicles to use when conditions – deep snow – get bad. On holiday weekends and stormy days we approach or exceed gridlock and it can take hours to get across town. From an operation point of view, SCADA tells us where system faults are located: on a distribution feeder or on the transmission system. This allows us to follow the first rule of problem solving: Define the problem.

The Quindar SCADA system uses a DEC Alpha Series Workstation with a hot stand-by. A short term UPS furnishes back-up power until our headquarters building auto transfer generation scheme kicks in. The graphical Man Machine Interface (MMI) was designed by Truckee-Donner personnel and is easily modified to satisfy changing system conditions.

We believe that one of the real advantages of our SCADA system was the ease of installation. Hardware interfacing was simple: add a communications board to each F4C, change out regulator controls to the CRA-CL5A, install a SCADA system serial interface, and interconnect with fiber optic cable. The work was done within the normal work schedule by two of our substation folks. Software interfacing presented the challenge described earlier but was likewise a breeze after we decided on the translation system.The SCADA system continues to pay for itself each month in the savings generated from open market purchases of power. Since this is our first full winter with the system in operation, we are just beginning to realize the added management benefits that come with real-time information about the conditions of our feeders. After we’ve had some time to digest what’s on our plate, we may implement Phase II of this project and extend the system to provide real-time information about the condition of our field switches.

When all is said and done there is one thing for certain: the snow will continue to fall in Truckee; the skiers will continue to come; and we’ll get occasional gridlock. But now when our crews go out on a service call we’ll know it’s for real. And in our kind of weather, that’s for real!

Truckee – What’s in a Name

Some folks think that the name for Truckee came from the railroad shops that once resided at the east end of the town. Well there is another explanation. When the Stevens party first traversed what is now present day Truckee their leaders met with the chief of the Paiute tribe. The Indians called out assurances of peace and used the Paiute word "trokay" over and over again. The word translates loosely to "everything is all right" or "its OK". The white men believed this was the chief’s name and referred to him as "Chief Truckee". The name stuck and the town was subsequently named after him.

Warner Brothers Comes to Town

Warner Brothers will shortly begin filming a story in Truckee and other locations based upon a jazz singer’s death and resurrection. Michael Keaton is expected to play the role of an overworked jazz musician who dies unexpectedly. God gives him another chance to make up for lost opportunities and he uses it to make up lost time with his son. The name of the musician? Why Jack Frost, of course. The name of the movie? Frost. Watch for it around Christmas this year.

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Introduction

In the era of electric utility deregulation and competition, reliability of service to the customer has become a critical issue. Cost control is also an important element in the competitive mix. In addition to customers demanding better service at lower cost, regulators are entering the picture in some situations with rate decisions tied to service reliability. The challenge for utility engineers and managers is deciding how resources should be spent on reliability to provide the customer the service that they demand, at a price that the customer is willing to pay.

Historically, electric utilities defined service reliability based upon recorded system data. The feasibility of new expenditures on the system was based on the measured service reliability data, ignoring momentary outages and other short duration events. The values for reliability were reported as system average values, which may say nothing about an individual customer’s experiences. Some short term events, which may be very important to the performance of loads in the customer facilities, were not even counted in the measurement index.

The perception of adequate reliability varies among customers served by the electric utility. Customers have a variety of needs, and demand different levels of service. As a result, some electric utilities are trying to develop a more customer-focused definition of reliability. The economic question can be considered through three different perspectives: the electric utility’s viewpoint, the customer’s viewpoint, and the regulator’s viewpoint. Each will yield a different set of conclusions regarding expenditures on system reliability.

Electric Utility’s View

From the electric utility’s point of view, the economics includes an expenditure of resources to improve reliability in order to generate increased kWh sales or customer loyalty, which translates into increased profits. However, there may or may not be a difference in the rate paid by the customer for service with higher reliability. In addition to the quantitative measures there are additional benefits such as decreased customer complaints, better public relations, and decreased pressure from the local regulators.

The problem with the economic analysis considering the added revenue from improved reliability is the fact that the benefit is small. For a typical customer consuming an average of 1kW of power, the utility gets less than $1 of extra revenues from each customer by increasing the availability of electrical service from 0.999 to 1.000. To make matters worse, increased revenue does not equal increased profit. A generous estimate of the additional profit would be about 10% of increased revenues. Thus, the additional capital available to improve the system from 0.999 availability to 1.000 without reducing profits is only about $0.10 per customer each year. The task of increasing the service availability to 1.000, even if possible, would certainly require a large expenditure for little return, hardly a formula for keeping a business healthy.

Another utility point of view might include an economic analysis of reliability improvement expense versus the total revenue stream to the utility from an important customer. This could be justified if the reliability improvement expenditures are needed in order to keep the customer from purchasing power from a competitor. Although one could make the argument that the competitor would still use the same electric transmission and distribution system, customers will still be persuaded to switch energy suppliers when current reliability is poor. By comparison, the automobile manufacturers in the U.S. over the past decade have improved the reliability of their products in order to retain existing customers, maintain revenues, attract new customers, etc. Utilities may be in a very similar situation, forced by the marketplace to expend resources on reliability improvement in the face of new competition.

Customer’s View

From a customer’s point of view, the cost of an outage may be far greater than the utility’s cost. Service interruptions, either momentary or sustained, can disturb industrial client processes resulting in lost production, scrapped material, and perhaps additional equipment cleanup and repairs. A recent IEEE IAS paper titled, "Power Interruption Costs to Industrial and Commercial Consumers of Electricity", summarized the costs in the following table based on a survey of 210 large commercial and industrial customers:

The table gives some indication that there is a significant cost to an industrial customer when power is disturbed or interrupted. Although a momentary outage is indicated as a lesser cost per incident, momentary outages may occur 10-20 times in a year. Similar cost estimates can be developed for smaller commercial and even residential classes of customers.

Regulator’s View

Performance Based Ratemaking (PBR) seeks to establish an environment that stimulates the monopoly service provider to improve efficiency and keep prices in line with inflation or less. Unfortunately, this can provide an environment where maintenance and other costs can be slashed in order to make money. In the distribution environment customers are captive. They cannot leave the supplier and connect to another provider.

An alternative is to include measurements of reliability in a Service Quality Index (SQI) for a distribution company subject to a PBR. The SQI will impose significant penalties on revenues if service quality deteriorates from a preset baseline performance level. The idea is to mimic the loss of revenue to the company that happens in a free market if customers leave a poor service provider to go to one with better performance.

In order to create a PBR service quality index, definitions must be created for evaluation of ongoing performance. Performance levels can be utility-specific to allow for different situations. If multiple items are included in the measurement process, an SQI specific for a utility and its history can be developed. One suggested approach would establish a rule that requires all utilities to measure certain service quality indices and report the data annually. With this data, a utility-specific SQI can be part of the rate plan that compares annual performance to baseline performance standards. The typical reliability measurements that are being adopted are SAIFI, SAIDI, and MAIFI. Pennsylvania, New York, and California have adopted these indices.

Penalties are included as part of the PBR for reliability reviews to discourage deterioration in service with cuts in the budget. California and New York will be incorporating penalties in their rate plans. Rewards (higher rates) are not generally part of the plans since it is not fair to assign higher costs to customers that receive better reliability than they want. Rewards and penalties might create a situation where poor performance in one area is balanced by good performance in another area. This might remove the incentive to improve the service to the poorly performing part of the system.

Reliability Improvement Initiatives

An unplanned customer outage is generally caused by a fault on the utility system. Although the number of faults that occur on the system directly impacts the resulting reliability indices, the response of the overcurrent protection system can also have a large impact on the number of customers out of service and the total outage time. Figure 1 shows the relationship of both factors to the development of the reliability indices. Many utilities are focusing reliability improvement initiatives around prevention aimed at reducing the number of faults. It can be shown that investments in response initiatives, such as the design of overcurrent protection systems that sectionalize the system after a fault event, also have a major impact on reliability results. Especially when considering the value of service to the customer, expenditures in the overcurrent protection system for reliability improvement can generate reasonable payback periods and rates of return. One reliability improvement study for an oil production company resulted in economic justification for installing reclosers on the primary distribution circuits serving the pump loads. Table 2 (see page 6) displays the recloser placement and economic summaries for the 19 circuits investigated in the system reliability study.

The results in the table demonstrate that for the majority of the circuits studied, reliability expenditures generate a very favorable rate of return, an average of over 50% annual return over a 15 year period. The only dilemma for the utility with this approach is that it bears the expense and the customer reaps the benefits. However, the competitive market may force electric utilities to make the system investments to maintain their present customer base.