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Electricity is a unique power source in that it must be used the instant it is generated—it cannot be stored or stockpiled in large capacities to meet future requirements. Generating capacities must be able to meet peak load requirements instantaneously. Since the first system to sell lighting to New York City was installed in 1882, this has created two problems: how to deal with the voltage drop during transmission across long distances, and how to meet widely varying voltage requirements. High-voltage alternating current (AC) and the development of transformers in the late 19th century resolved these problems and made possible efficient distribution systems that would meet wide-ranging customer requirements. They also led to the phenomenal growth of the electric industry.

The electrical systems in use before the turn of the century were direct current systems. The generation systems were small, the distribution network was limited, and the voltage levels were low. Alternating current distribution systems developed rapidly, when it was recognized that interconnecting generation sites produced economic benefits. The need for higher voltages became apparent as electrical networks increased in size and power-carrying capability.

Although simple in concept, current electrical distribution equipment and systems are characterized by highly sophisticated technologies that continue to develop rapidly. Because electricity is invisible and its effects are not readily discernible, a mathematical approach is needed to achieve a full understanding of the design and operation of modern distribution systems. This requires highly technical training and is beyond the scope of this manual; the intent here is to describe the physical devices, their purposes, and their relationships to provide a more general understanding of the systems.

Presently, transmission lines in the United States carry voltages of 345,000, 500,000, and 765,000 volts (V). For distribution systems, utilities use 12,000, 12,470, 13,200, 69,000, and 138,000 V. The primary voltages for medium to large customers are 12,000, 12,470, 13,200, 4,160, and 2,400 V. There is no fixed cutoff between subtransmission and transmission, or subtransmission and distribution. The voltage ranges overlap somewhat. Voltages of 69 kV, 115 kV, and 138 kV are often used for subtransmission in North America. As power systems evolved, voltages formerly used for transmission were used for subtransmission, and subtransmission voltages became distribution voltages. Like transmission, subtransmission moves relatively large amounts of power, and like distribution, subtransmission covers an area instead of just point-to-point. The following three main research projects dealing with higher transmission line voltages were conducted:

  1. 1,000-kV line, by the Bonneville Power Administration
  2. 1,000-kV line, by the Electric Power Research Institute (EPRI) and General Electric Company
  3. 2,000-kV line, by American Electric Power (AEP) and the Swedish corporation Allamanna Svenska Electriska Aktiebolaget (ASEA)

The studies revealed that transmitting at higher voltages results in higher power transfers over long distances due to increase in surge impedance loading (SIL), reduction in current and energy losses.

However the studies also revealed that a higher inventory of spare equipment would be needed to reduce the exposure to extended outages. In addition, industry standardization for UHV (Ultra High Voltage) equipment is not as advanced as for comparable EHV (Extra High Voltage) equipment. There were also insulation challenges for lines passing through high altitude and polluted areas. The studies also determined that increased impedance of a transformer at each line terminal increases losses and cost. Adding a new voltage overlay also requires a large investment in tools, equipment, and training.

The above transmission voltages thus remain unproven in commercial application. In addition, dramatic reductions in load growth and the development of natural gas-fired generation close to load centers subsequently deferred the need for long-distance transmission projects.

The first 735-kV transmission lines were built by Hydro-Québec in 1965. Although efforts continued to establish the technical feasibility of power transmission in the range of 1000-1500 kV, practical implementation of transmission systems at these voltages was not feasible because of a steady decline in load growth following the energy crisis that began in 1973. Transmission lines in the range of 1000-1200 kV were built in Russia (the former USSR) and Japan, but the Russian line, after a few years of operation at the design voltage of 1150 kV, has been operated at the lower level of 500 kV, while the Japanese 1000-kV line has also been operated at 500 kV since it was built. Thus, the highest operating transmission voltage in different countries around the world continues to be in the range of 700-800 kV.

The introduction of high-voltage direct current (HVDC) transmission lines has opened new horizons. The advantage of HVDC over AC for long distances is its lower cost. Presently, the break-even point is 500 miles. For transmission lines longer than 500 miles, HVDC is cheaper than AC, and for lines shorter than 500 miles, AC is cheaper. When using HVDC, doubling the voltage of a cable increases the power-carrying capability of the cable by fourfold. However, as the network voltages increase, so do the costs of design, installation, and maintenance.

UHVDC (ultra-high-voltage direct-current) is shaping to be the latest technological front in high voltage DC transmission technology. UHVDC is defined as DC voltage transmission of at least 800,000 volts (HVDC is generally just 100,000-600,000 volts).

One of the biggest issues with current HVDC super grids are that they suffer from large losses of power as the length is extended. Increasing the transmission voltage on such lines reduces the power loss, but until recently, the inter-connectors required to bridge the segments were prohibitively expensive. However, with advances in manufacturing, it is becoming more and more feasible to build the UHVDC lines.

In 2010 ABB Group built the world’s first 800kV UHVDC transmission line between Xiangjiaba and Shanghai China. The line crosses a total length of 1907km (1192mi). Since the Xiangjiaba-Shanghai line was completed in 2010, at least 12 other Chinese UHVDC transmission lines have been completed and about 5 more are still under construction. Some of the completed lines run at 1 million volts and span 2500km. Lines up to 5000km are currently being planned.

While China has been where the most recent UHVDC technology has been deployed, there are a few deployments others other areas too, notably in Europe and America.

In 2017, a powerline transmitting wind energy from Oklahoma to Tennessee is expected to be built as the first UHVDC cable in the United States. The line is expected to be 1,100 kilometres (680 mi) long between the Oklahoma panhandle and the western part of Tennessee with a voltage of 600kV. Construction is due to begin in second half of 2017.

The electrical distribution systems described here are typical of university-owned facilities where electricity (whether generated on campus, purchased, or both) is received and further distributed to points on campus. Not covered are situations where a municipally or commercially owned electric utility furnishes electricity in utilization voltages to individual buildings.

College and university electrical distribution systems generally consist of (1) a switching station for receiving the electricity into the university system, (2) switching substations (which include transformers), (3) medium-voltage conductor circuits, (4) electric power generation, and (5) system protection.

Switching Stations


Switching stations perform a number of essential functions. They switch electric power from a larger transmitting system to the college or university system and switch the electric power that is generated on campus into the system. A switching station normally has more than one feed, or there is more than one station serving the college or university system, each with a separate feed. The station provides for switching between feeds as necessary.

A two-feed system is recommended for greater reliability of service. During normal operation, each feeder carries about half of the campus load, in which case the tie switch connecting the two feeders remains open. If a feeder is lost, the feeder switch opens, and the tie switch closes, thus minimizing power interruptions. This switching can be manual or automatic. For life-sustaining applications such as medical facilities, a triple-feed system is advisable, if economically feasible.

The switching station reduces high-voltage electricity from the incoming system to the voltage that is required by the college or university distribution system. For safety and economy in equipment costs, and because of limited transmission distance, university systems usually operate at lower voltages. The transformers in the switching station reduce incoming voltages to levels at which a university or college system is designed to operate. Normally, the incoming voltage to a university campus is 4.16, 4.8, 12, 12.47, 13.2, 34.5, 66, or 138 kV, depending on the campus size. The campus distribution voltages are 13.2 kV, 12kV, 12.47kV, 4.8kV, 4.16 kV, and 480 V.

Finally, the switching station houses fault detection and circuit interruption facilities to protect the institution’s system from exterior faults and overcurrents.

Switching Substations


Substations in the distribution system perform functions similar to those performed by switching stations. They switch the electric service of the supply mains from the switching station, usually located on the campus periphery, to feeders that supply campus areas. Substations contain sectionalized assemblies of switches, circuit breakers, and metering equipment that control and monitor electrical service to the feeders, which in turn supply individual buildings or groups of buildings. Substations may house transformers for stepping down the power to utilization voltages or to an intermediate voltage. The elements of a substation include (1) switches, fuses, and circuit breakers; (2) switchgear; and (3) transformers.

Switches, Fuses, and Circuit Breakers

Switches are circuit-interrupting devices that can make, break, or modify the connection in an electrical network, typically only under normal circuit conditions. Fuses are overcurrent protective devices that interrupt the circuit under fault (abnormal) conditions and usually are employed in combination with switches. Circuit breakers are switching devices that can make, carry, and interrupt the circuit under normal conditions and under special abnormal conditions. Therefore, switches are used only during normal operations, fuses operate only when abnormal conditions occur, and circuit breakers can perform during either condition. Switches, fuses, and circuit breakers are rated based on the system voltage, continuous current capacity, and short-circuit current interrupting capacity.

Circuit Interruption

Assume that a purely resistive load is connected to a system. The switch is closed, and the system is energized. At the time the switch begins to open and the contacts are separated, an arc is drawn between the two contacts, thus generating high temperatures. The high temperatures ionize the medium, creating a plasma between the contacts and sustaining the arc. As the current waves pass through zero, arcing ceases, and the voltage across the contacts increases. As the voltage builds up, a restrike occurs owing to the high electric field and the hot plasma still available from the initial arc. The above process continues and additional restrikes occur until the contacts have opened wide enough and the plasma has sufficiently cooled that a restrike cannot occur. At this point the circuit is interrupted.

Because in a resistive circuit no energy is stored in the system, current and voltage are in phase. If the contacts can withstand the arcing, the circuit will be eventually interrupted in a few cycles at most. However, if there are reactive elements in the system (particularly if there is a capacitor), arc quenching can be a problem.

Two parameters must be considered when opening a circuit-interrupting device: transient recovery voltage (TRV) and the rate or rise of recovery voltage (RRRV). If a device has a higher RRRV than the system, then the dielectric value between the two contacts grows faster than the system, and therefore no restrikes can occur. Similarly, if a device has a higher TRV than the system, then the dielectric value between the contacts can withstand the peak system transient voltages, and no reignition can occur. Therefore, quenching the arc and avoiding restrikes are key elements in the operation of circuit interrupting devices, and different technologies have been developed to address this problem.

Interrupter Switches

Interrupter switches employ unique techniques for extinguishing the arc by lengthening it, squeezing it, and cooling it. On opening, the switch blade separates from a set of contacts in the arcing chamber and draws an arc, which increases in length as the blade moves. Within the arcing chamber, the arc is squeezed by a mechanism that compresses it. Furthermore, the hot arc is allowed to play on the special quenching materials that line the arcing chamber and generate gases that cool the arc. Ultimately, through the processes of elongation, constriction, and cooling, the arc is extinguished. Interrupter switches typically are used on systems rated at 4.16 through 34.5 kV, with current-interrupting capabilities of up to 1,200 amperes and with the capability to withstand momentary currents of up to 61,000 amperes. Interrupter switches may also have a duty cycle fault closing rating, permitting them to close into a fault a specified number of times while remaining operable and capable of carrying and interrupting their rated continuous current.


Fuses are overcurrent protective devices designed to interrupt the circuit when a fault condition occurs. There are essentially two types of fuses: solid-material fuses and current-limiting fuses. Solid-material fuses employ a fusible element in air surrounded by a solid-material medium that generates deionizing gas from the heat of the arc. Fast, positive fault interruption is achieved by high-speed elongation of the arc within the fuse tube and by the efficient deionizing action of the gases liberated from the solid-material arc-extinguishing medium. The arc is lengthened by a spring-charged mechanism within the fuse that is released when the fusible element melts owing to an overcurrent, thereby separating the contacts at high speed. With power fuses, the arc extinguishes at a natural current zero.

Current-limiting fuses employ a fusible element surrounded by sand. An overcurrent melts the fusible element, and the arc formed causes the surrounding sand to vitrify, which in turn creates a glass tunnel that confines the arc. Rapid cooling and restriction of the arc increases its resistance. As a result, the current is reduced and forced to an early current zero before its natural zero. This causes high-voltage surges on the system, much like those occurring in any device that uses a vacuum as the interrupting medium.

Power fuses and current-limiting fuses have other significantly different performance characteristics that affect their suitability for circuit protection. Power fuses contain fusible elements that are indestructible and do not age. The time-current characteristics of power fuses are permanently accurate; age, vibration, and extreme heat caused by surges will not affect the characteristics of these fuses. There is no need for safety zones or setback allowance. Because of these performance characteristics, power fuses allow fusing closer to the transformer full-load current, providing the maximum degree of protection against secondary-side faults. This attribute also facilitates coordination with upstream protective devices by allowing the use of lower ampere ratings or settings for these devices, resulting in faster response.

The construction of current-limiting fuses, on the other hand, makes them susceptible to element damage caused by in-rush currents approaching the fuse’s minimum melting time-current characteristic curve. Because of this potential for damage, and because of the effects of loading and manufacturing tolerances on the time-current characteristic curve, a safety zone or setback allowance typically is required. This safety zone or setback allowance, combined with the shape of the time-current characteristic curve, results in the selection of a current-limiting fuse ampere rating that is substantially greater than the transformer full-load current. However, the use of such a high ampere rating is undesirable because the degree of transformer protection will be reduced, and thus coordination with the upstream protective device may be jeopardized. Also, because high-ampere-rated current-limiting fuses typically require the use of two or three lower ampere fuses connected in parallel, increased cost and space requirements may result.

Selection of the various types of protective devices and their ratings and settings is a complex matter. However, publications are available that provide complete, simplified procedures for selecting the optimal fuse, taking into consideration all factors associated with the application. Fuses typically are used on systems rated from 4.16 kV through 34.5 kV and are available with continuous current ratings of up to 720 amperes and with short-circuit interrupting ratings through 50,000 amperes symmetrical.

Circuit Breakers

Air Circuit Breakers: Air breakers use the simplest technique for extinguishing the arc: they lengthen it, and in this way can interrupt up to 30 times their full rated current. Air circuit breakers are of different types. A horn-gap type uses V-shaped arc-interrupting devices. As the contact is opened, the arc is drawn at the bottom of the horn. However, because of higher temperatures and electromagnetic forces, the arc moves up the horn. As the arc becomes larger, it is cooled by convection. Another style is the molded-case circuit breaker, in which the arc is cooled by forcing it to go through narrow insulated fins called arc chutes. Air circuit breakers are used for low-voltage systems (up to 600 V) with current-interrupting capabilities of up to 100,000 amperes.

Air-Magnetic Breakers: In an air-magnetic breaker, the magnetic field is applied on the arc, forcing it along a number of insulating fins. As the arc lengthens, it cools down and extinguishes. Two sets of contacts operate in air-magnetic breakers: main and arcing contacts. The arcing contacts carry the current when the main contacts open, so arcing contacts are first-make, last-break contacts.

The arc chute where the arc is extinguished consists of a number of insulated fins. The arcing contacts initiate the arc above the bottom of the slot, which establishes a magnetic field before the arc is drawn. The arc runner configuration moves the arc up the chute. In the meantime, the air puffer blows a jet of air across the contact to help move the arc up the arc chute. Air-magnetic breakers are used for systems of up to 15kV with interrupting ratings as high as 1,000 MVA. Currently, only a few companies still manufacture air-magnetic switches and circuit breakers. Several manufacturers make conversion kits that use vacuum switches for existing air-magnetic switch cubicals.

Oil Circuit Breakers: In an oil breaker, the arc is drawn under oil. As the arc is established, oil around the contact is vaporized and a large bubble surrounds the arc. Hydrogen comprises roughly two-thirds of this bubble, and because hydrogen is an unfavorable gas for ion pair production, the arc is cooled and interrupted.

Oil breakers are used outdoors for up to 345 kV. At 345 kV, they are capable of interrupting currents as high as 57,000 amps. Environmental requirements for oil circuit breakers are not as stringent as those for an air-magnetic circuit breaker, but oil breakers are prone to fire and explosion.

Vacuum Circuit Breakers: A vacuum is an ideal environment in which to open switch contacts. As the contacts open in a vacuum, an arc is initiated, but because of the high dielectric value of the vacuum, the arcing plasma cannot maintain itself and is extinguished in less than 20 microseconds. The arc is interrupted at first current zero and usually does not reignite. A 1/4-in. gap is sufficient to interrupt 100 kV. Vacuum breakers do not require a supply of gas or liquid, so they are not fire or explosion hazards. Unlike oil breakers, they can be installed in any environment. They are compact and lightweight, and switch operation is silent and requires relatively small amounts of energy. Vacuum circuit breakers can be used outdoors, in manholes, or in metal-clad switchgear for indoor operation. Vacuum switches are rapidly becoming the most popular types of switches for 4.16- and 13.2-kV systems.

Sulfur Hexafluoride Circuit Breakers: Sulfur hexafluoride (SF6) circuit breakers have been in use since the 1960s. Here the arc-extinguishing medium is a colorless, odorless, nontoxic, noncorrosive, nonflammable, inert gas with an excellent dielectric value. These breakers are available for voltage loads ranging from 13 to 765 kV. The remarkable performance of SF6 as an arcing medium is due to its ability to recover quickly; it is almost 100 times more effective than air in extinguishing the arc.

Sulfur hexafluoride breakers have many advantages. They are light weight, self-quenching, and compact; present no fire hazards; and can be installed in any position. The ambient environment for SF6 breakers is less restrictive than for other types. The disadvantage in using SF6 breakers is their high cost. However, as technology improves, they will become more cost-competitive with oil and air-magnetic breakers.

Metal-Clad and Metal-Enclosed Switchgear

This is a particular type of electrical equipment in which the circuit breakers, disconnecting devices, relays, metering, potential transformers, and current transformers are in separate metal compartments. When the switch assembly is removable, it is called metal-clad; when it is not removable, it is called metal-enclosed. This type of switchgear normally is used for voltages between 13.2 and 34.5 kV.


Different generation, transmission, and utilization requirements dictate different voltage and current combinations, hence the need for a component capable of changing or transforming voltage and current at high power levels in a reliable and effective way. This is the function of the power transformer, an extremely important link between the transmission and use of electric power. Transformers make it possible to generate energy at any suitable voltage, change it to a much higher voltage for transmission over long distances, and then deliver it to a college or university system at still another voltage.

All transformers have two basic elements: two or more windings insulated from each other and from the core, and a core that usually is made of thin, insulated, laminated sheet steel. Power transformers used for stepping down the voltages in a distribution system are classified according to type of core construction and type of cooling employed.

Two types of core construction are core and shell. In the core type, the magnetic circuit comes in the form of a single ring, with the primary and secondary windings encircling the two legs of the core. In the shell type, the relative positions of the coils and the magnetic circuit are reversed. Here the winding forms a common ring in which two or more magnetic circuits are interlocked.

Transformer Ratings

Like most other electrical equipment, transformer limitations are thermal in nature. The nameplate data indicate the permissible winding temperature when the transformer is at full load. If the windings are subjected to sustained high temperatures, insulation life will be tremendously shortened, which may result in system failure.

It is important to note that the temperature rise in a transformer, or any other electrical equipment, is a function of kilovolt-amperes and not of kilowatts. Moreover, the nameplate data are based on 40°C of ambient temperature; if the ambient temperature is higher, the nameplate rating should be reduced according to the manufacturer’s relevant data.

Transformer Insulation Classes

There are currently four insulation classes with their respective National Electrical Manufacturers’ Association (NEMA) specification and temperature limits. In Class A transformers, provided they are operated at a maximum ambient temperature of 40°C, the temperature rise on the winding will not exceed 55°C. Class B transformers use a higher-temperature insulating material, so at an ambient temperature of 40°C or lower, the temperature rise on the winding will not exceed 80°C. For Class F transformers, at an ambient temperature of up to 40°C, the winding temperature rise will not exceed 115°C. Class H transformers use insulation that can withstand high temperatures and are the most compact transformers. At an ambient temperature of up to 40°C, the winding temperature rise will not exceed 115°C.

Transformers in Parallel

When the load increases so much that one transformer cannot meet the power demand, an additional transformer can be connected in parallel. If two transformers are connected for parallel operation, the turns ratio and the impedance of both units must be examined to ensure proper load sharing between the two, with little or no circulating current. Otherwise, one transformer might be overloaded while the other is lightly loaded, or the circulation current between the two units may be such that one unit will be overloaded with a relatively small load. This situation will result in high energy losses without utilizing the full capacity of both units.

When two transformers are installed in parallel, the units must be a matched set. This means that in addition to primary and secondary voltages, the line frequency, transformer connection, turns ratios, and impedances are such that they will share the load based on their relative kilovolt-ampere ratings. If both transformers have the same ratio, then the turns ratios and impedances are almost identical. For two transformers with identical 3 percent impedances (which is typical of most distribution transformers), a 1 percent difference in turns ratio can result in a 15 to 20 percent circulating current. In addition to creating higher losses, circulating currents reduce the total capacity of the transformers.

Transformer Types

There are three common types of transformers: dry, mineral oil, and polychlorinated biphenyl (PCB).

Dry Transformers: Dry transformers use air as coolant. Air circulation is achieved either by natural convection or by a forced-air system. Dry transformers usually are larger than oil or PCB transformers of equivalent rating. They are explosion-free, self-extinguishing, and less expensive, and usually are used for relatively small loads. The ambient condition is important for dry transformers, as a source of clean, filtered air is needed.

Oil Transformers: Oil transformers are the workhorses of power distribution systems. They can be self-cooled, using natural circulation of the oil, or air-cooled with blowers. The transformer’s core and winding are surrounded by insulated mineral oil, which protects the insulation and provides cooling and dielectric strength to the transformer. Because the oil must be able to withstand voltage surges and thermal and mechanical stresses, as well as act as a good coolant during the entire useful life of the transformer, the oil should be supplied or approved by the transformer manufacturer, and adequate care should be exercised to guard against its deterioration.

The major causes of oil deterioration are water and oxidation. Moisture contamination can result from condensation, especially when the transformer is down; such contamination drastically reduces the oil’s dielectric strength. An increase in water of 10 to 50 ppm reduces the dielectric strength by half. Oxidation causes oil deterioration, which results in sludging. Oil transformers are used both outdoors and indoors. Because they are fire hazards, when used indoors, they must be installed in a vault to conform to fire codes.

PCB Transformers: PCB is a dielectric fluid that has been used in transformers and power capacitors since about 1960. It is a stable compound that has good fire resistance. Manufacturers of transformers have preferred PCB over mineral oil, because PCB transformers do not require a vault. PCB liquid is known primarily under the brand name of Askeral. Other common trade names in the United States are Aroclor, Asbestol, Chlorextol, No-Flamol, Pyronal, Elemex, Dykanol, and Interteen.

In 1976, Congress enacted the Toxic Substances Control Act, which required the Environmental Protection Agency to establish rules governing the disposal and marketing of PCBs. From that point on, these PCB-filled devices were regulated. Since that time, practically all but a small number of PCB transformers have been either replaced or retrofilled.

A non-PCB transformer is any transformer that contains oil/dielectric fluid less than 50 ppm PCB. Any transformer that contains greater than or equal to 500 ppm PCB is classified as a PCB transformer.

Spills that occur in outdoor electrical substations must be decontaminated to a concentration of 100 micrograms per 100 square centimeters for solid surfaces. Contaminated soil must be cleaned to a concentration of 25 ppm (i.e., soil must be excavated so that any residual remaining is 25 ppm PCB or less). Alternatively, contaminated soil may be cleaned to a concentration of 50 ppm provided that a label or notice is visibly placed in the area.

Spills that occur in restricted-access locations (i.e., areas located > 0.1 kilometers from a residential or commercial area and where accessibility is limited by manmade or natural barriers) must be cleaned to a concentration of 10 micrograms per 100 square centimeters for all solid surfaces. Contaminated soil must be excavated to a level of 25 ppm PCB or less.

Spills that occur in nonrestricted access locations (residential and commercial areas such as indoor locations and unrestricted rural areas) must also be decontaminated to a concentration of 10 micrograms per 100 square centimeters for all solid surfaces. Contaminated soil must be cleaned to a level of 10 ppm PCB, provided that the soil has been excavated to a depth of at least 10 in. and the soil has been replaced with clean fill containing less than 1 ppm PCB.

High-Voltage Conductors and Circuits


There are two basic circuit systems for feeding from the substations to building systems: the radial system and the network system. In the radial system, separate feeders radiate from the substation, each supplying an area. From these feeders, subfeeders, or branches, split off to transformers serving individual buildings or a cluster of buildings. The radial circuits are equipped with tie switches so that in the event of a fault, the circuit can be supplied by another feeder. Radial feeders with loop or throwover switching are most commonly employed.

In the network system, the secondaries of two or more transformers are tied together. Adjacent transformers may be supplied from the same or different feeders. Distribution, therefore, is normally at utilization voltages.

Three principal factors determine the distribution voltages: (1) energy loss in transmission versus cost of equipment, (2) strength of the conductor, and (3) overhead versus underground installation. There is a trade-off between the cost of energy loss in transmission and the cost of transmitting equipment. For a given percentage energy loss in transmission, the cross-sectional area, and consequently, the weight of the conductor required to transmit a block of power varies inversely as the square of the voltage.

The strength of conductors also must be considered. Overhead transmission lines must be strong enough to carry any load that may be reasonably expected. The most severe loads are experienced during winter ice and wind. Underground conductors must be able to withstand allowable stress to which the cable is subjected during installation. The need for adequate physical strength of a cable will help determine its electrical conductive capacity.

When comparing costs on overhead or underground transmission lines, it should be noted that the cost of underground construction is much higher. Overhead lines, however, are unsightly and detract from the educational environment. They also create problems of routing to building transformer vaults, as these often are located in basements. As a consequence, underground transmission lines are most commonly used in new installations.

The power cables are critical elements of the high-voltage network, because they are the arteries of the system. Traditionally, they are the system component that receives the least attention, perhaps because “out of sight is out of mind.” Cables usually are located in duct banks, and insulation that weakens prior to failure cannot be seen, which often results in inadequate maintenance. It is important to realize that the reliability of the electrical network can be greatly improved and costly downtime avoided simply with a little attention to the cables.

Cable Insulation

Paper-impregnated lead cable (PILC) and varnished cloth (VC) have been the insulation workhorses of the industry since 1910. PILC has compound migration problems if used on vertical risers, and termination and splicing also are more difficult. VC cables are relatively more expensive for the quality of the dielectric but do not have the compound migration problems. The combination of VC cable for vertical risers and PILC for horizontal runs has been used successfully.

Since the 1970s, the petrochemical industry has introduced a variety of polyethylene compounds (XLPE, EPR) as insulation materials, all of which have good insulating characteristics, such as high moisture resistance, low temperature characteristics, high ozone resistance, and greater abrasion resistance. These cables are lighter in weight compared to PILC, and terminations and splicing are relatively easier. The most popular compound is Ethylene Propylene Rubber (EPR), which is widely being used in the manufacturing of medium voltage cables. This compound offers excellent high moisture resistance, high discharge resistance, low temperature flexibility and low resistance to water treeing.

Termination and Splicing

There are different splicing kits available, and manufacturers have a wide variety of techniques for splicing. Therefore, it is important to first make sure that the proper size and type of splice are used for every situation, the manufacturer’s recommendations are followed, and the work is performed by skilled personnel. Cable splices and terminations are usually the weakest points in a cable system, so adequate attention must be devoted during installation and subsequent maintenance.

Cable Maintenance

Insulation Resistance Test: This test determines the insulation resistance between the conductor and ground. A megohmmeter is used to measure the resistance. It is basically a high-voltage ohmmeter consisting of a small DC generator and a milliampere meter. The generator is hand cranked or driven by an electric motor, the latter being preferred for consistency of rotor speed. Megohmmeters generally have ranges from 100 V to 5,000 V.

Good insulation is indicated by an initial dip of the milliampere meter pointer toward zero, followed by a steady rise; the initial dip is due to the capacitive effect of the cable. If the pointer makes slight twitches down scale, however, this implies current leakage along the surface of dirty insulation. To compare the insulation with the historical record, a spot test is performed. The megohmmeter is applied for 60 seconds, and the reading is recorded at the end of this time.

Dielectric Absorption Test: This test provides better information than the spot test but takes considerably longer than the insulation resistance test. Because the current is inversely related to time, insulation resistance will rise gradually if the cable is good and flatten rapidly if the insulation is faulty. The insulation resistance is plotted against time.

High Potential Test: The above two tests cannot determine the dielectric strength of cable insulation under high-voltage stress. A high potential test, or hipot test, applies stress beyond what a cable encounters under normal use. It is the only way to obtain proof that the cable insulation has the strength to withstand overvoltages caused by normal system surges. There are two types of hipot tests, AC and DC. The AC hipot test is used almost exclusively for insulation breakdown.

Very Low Frequency (VLF) Test: A VLF test is a go/no-go test and is not a diagnostic test, but is one of the best ways to check the AC integrity of an electrical asset to determine a pass or fail result. A very low-frequency voltage is applied to test the existing cable. Frequency ranges used are within the range of 0.01 Hz to 0.1 Hz. Test voltage levels are calculated using a multiple of the cable‘s nominal voltage, and are in the range of 1.5 U0 to 3 U0. The VLF cable testing time varies from 15 to 60 minutes. The object is to grow the defects through the insulation until the cable fails, then the aged part of the cable can be replaced. VLF testing can be considered a short and economical testing criteria for network operators.

Tan Delta (TD) Test: The Tan Delta test uses a very low frequency voltage source and a separate divider to make the measurements; the voltage is raised in steps while measuring the TD of the cable. A perfect cable behaves like a capacitor where there is a phase shift of 90° between the voltage and current. The more degraded the insulation and accessories are, the more this angle becomes less than 90°, as resistive leakage current is added. This change in the angle is easily measured and assumptions are made about the degree of degradation. The absolute TD number is important; however if the curve trends sharply upward as the voltage is raised, the cable is highly degraded. Based on the test values, cables are rated as Highly or Moderately Degraded, or Good. This data is used to help prioritize cable replacement, injection, and/or to determine what other tests may be of value. TD testing is easily performed and interpreted.

Partial Discharge Test: The Partial Discharge test reveals the defects in a cable by measuring the discharges in picocoulombs (pCs). The equipment uses a test frequency of between 0.05 Hz to 0.5 Hz to energize the cable up to a voltage level of 1.3 U0. This voltage helps to generate the partial discharge activities in the cable without causing unnecessary high electric stresses on the dielectric materials. The discharges are then captured and measured by high-speed transient recorders or oscilloscopes. The difference in the traveling time between the first incoming pulse and its reflection via the remote end of the cable is used to compute the locations of partial discharge along the cable.

DC hipot tests for cable maintenance must be performed offline and should not be performed on field-aged XLPE or EPR cable, as they are detrimental to the cable and reduce the life of the cable. These tests should thus be limited to cables that are not more than five years old and the exact DC voltage that needs to be applied to these cables shall be consulted with the manufacturer of the cable. Very Low Frequency testing, Partial Discharge testing, and Tan Delta testing as described above should be utilized for cable maintenance testing. These tests identify the defects in the cable, are nondestructive, and do not affect the life of the cable.

Surge Arresters

Surge arresters protect an electrical apparatus against overvoltages from lightning, switching surges, and other disturbances. Without arresters, flashover and equipment damage can result. During normal system voltages, arresters are dormant. When a high-voltage impulse is imposed on the system, regardless of source, the arrester will ground it, thus preventing it from going through the equipment. There are three classes of surge arresters:

  1. Station class arresters: This is the best type of arrester, as it is capable of discharging the most energy.
  2. Intermediate arresters: These have lower energy discharge capability than station class arresters.
  3. Distribution arresters: These have the lowest energy discharge capability and the least desirable protection level.

Electric Power Generation



Generators are electromechanical devices that convert mechanical energy into electrical energy. Generator operation is based on Faraday’s Law, which states that a voltage will be induced on a conductor if the conductor moves through a magnetic field. The voltage induced is directly proportional to the number of turns in the conductor, the strength of the magnetic field, and the speed at which the conductor moves through the field. In addition, the closer the magnetic field is crossed at 90°, the higher the voltage. Types of generators include AC synchronous, asynchronous, emergency, and DC. Most of the generators currently used in industry are synchronous.

AC Synchronous Generators: A synchronous generator is structurally identical to a synchronous motor. The magnetic field is produced by a direct current in the rotor circuit. The rotor, also called the exciter, is powered by brushes and slip rings. The armature circuit in the stator produces the electricity. There are a number of ways to power the exciter field. One is to supply it from a separate DC generator, but in most cases the exciter is fed from the armature through a diode and a silicone-controlled rectifier (SCR). The diode converts the AC power to pulsating DC, and the SCR provides voltage regulation. Here the generator is initially excited by residual magnetism.

A third way to power the exciter field is to have two rotors—one main, one auxiliary—on the same shaft. The small auxiliary winding is excited initially by residual magnetism. The AC voltage generated in the winding goes through a set of diodes and supplies the main rotor. In addition, a stationary exciter field regulates the voltage output of the generator. Because the entire exciter circuit is on one shaft, there is no need for brushes and slip rings. These units are called brushless generators and require less maintenance than other generators.

Asynchronous Generators: If an induction motor is driven faster than synchronous speed by a prime mover, it will become a generator. Because the generator speed is different from synchronous speed, the generator is called an asynchronous generator. The generated power frequency varies but is always more than 60 Hz. Asynchronous generators are simpler in construction and cost less than synchronous generators. This is why most small cogeneration units use asynchronous units. Also, if the prime mover energy is not controllable, such as in wind-powered generators, asynchronous units are the most appropriate. The power output of an asynchronous generator usually is not used directly; instead, it passes through a rectifier bridge to convert it to pulsating DC power. The DC power feeds an inverter, which converts the power to constant 6O-Hz AC power before it supplies the load. Harmonics can be a problem in these units, so their size is limited to less than 150 kW.

Emergency Generators: In using emergency generators, both the normal power source and the emergency generator are connected to a transfer switch. If the normal power source fails, the emergency generator is started. In about six seconds, the generator attains its rated voltage and frequency, and a transfer switch sends the load over to the emergency generator. When the normal power source is restored, there is usually a 6- to 10-second delay before the load is transferred back to normal power. This transfer can be done manually as well as automatically, depending on the configuration of the transfer switch.

When the normal power goes out and then is restored, the power to the load is interrupted twice, presenting a potential problem for computers, digital private branch exchanges (PBXs), and life-sustaining equipment. In such applications, an uninterruptible power supply (UPS) is used. In a UPS, AC power is obtained by connecting battery power with the use of inverters. The transfer switch and the generator are connected to the battery charger, which supplies power to the batteries. The load does not sense any normal power interruptions unless both the normal power and the emergency generator are out of operation and the battery charge drops below a certain point.

Cogeneration (see also Energy Generation Alternatives chapter):  The electrical concerns related to the interconnections of the cogeneration plant to the utility power grid are examined in the following section.

Cogeneration is the production of more than one form of energy simultaneously; it usually refers to producing electricity and heat energy.

When allowing interconnection of cogeneration, utilities are mainly concerned that the systems do not jeopardize the safety of utility personnel and the quality of service. During normal conditions, the utility needs to know if the power produced at the cogeneration site will be used entirely by the customer, and if not, how much of the power will be sold to the utility. Moreover, the utility wants to ensure that the harmonic voltage and frequency tolerances of the dispersed generation site meet the grid tolerances. During emergency conditions, network faults must be detected by the cogeneration device and isolated from the grid.

The utility electric distribution network is radial, so isolation of an area requires opening and locking a main circuit breaker. With cogeneration, the power network is not radial, but instead is a loop distribution system. Therefore, it is crucial for the utility to record the location of all cogeneration units and have access to a manual load-break disconnect at all times. The interconnection requirements of a cogeneration system depend on interconnection voltage, transformer configuration, protection scheme considerations, and onsite load and generation capacity.

Electrical Protection for Cogeneration: In a utility distribution network, the overcurrent equipment is arranged in a series of overlapping zones to clear a fault on a prearranged sequence of primary devices and backups. This is achieved by coordinating the time-current characteristics of fuses, circuit breaker reclosers, sectionalizers, and relays from a substation. In a faulted condition, the available current drops as it moves from the substation to the customer site because of an increase in system impedance. Therefore, coordination is relatively simple. With cogeneration interconnection, a bidirectional power flow on the distribution system can continue to energize the part of the network separated from the utility system reference source. Moreover, a cogeneration site can contribute additional overcurrent during faults, which may cause protective systems to operate prematurely.

This high current level from the cogeneration site is over and above the available fault current from the utility, thus shortening the average melting time of the line fuses. In a 15-kV system, a small synchronous cogeneration unit of a few megawatts can reduce the fuse melting time by more than 30 percent; in an induction generator, the reduction in melting time is about one-third that of the synchronous generator.

Another problem lies with the utility’s autoreclosures. The faults that occur with an overhead transmission system are usually momentary and self-clearing. After a fault, the autoreclosure closes the circuit a few cycles after the circuit is interrupted, and the customer down time for such momentary faults is minimal. With cogeneration in the system, although the utility breaker has interrupted the circuit, the fault is fed by this unit and does not get a chance to clear. Therefore, when the circuit is closed by the autoreclosure, the fault has not cleared, and this increases downtime. The presence of cogeneration changes the available fault and the system coordination for in-house systems, as well as the utility grid.

Another concern utilities have with cogeneration is the problem of islanding. Islanding means that the cogeneration site is operating independently of the reference voltage and frequency of the utility power grid and is no longer in synchronism with it. Islanding can cause several problems. Utility personnel might assume that opening the line breaker will de-energize the circuit. The generator voltage and frequency variations might cause costly damage to the load. If the utility breaker is closed without synchronizing the cogeneration unit, serious damage can also be incurred by the generator and the breaker.

The harmonics generation from cogeneration sources must also be studied. For economic reasons, the magnetic core of in-house generators is not made of the same high-quality materials as the utility grade units, and the core nonlinearities of cogeneration units produce harmonics that cause problems with computers and other sensitive electronic equipment.

Minimum Protection Requirements: If an internal electrical fault occurs within the cogeneration unit, the available fault from the utility grid will cause major damage. Therefore, the electrical protection needs of a cogeneration system should not be taken lightly. The required protection depends on unit size, generator type, in-house load, and interconnection voltage. For small units where power is totally used in-house, overcurrent, over- or undervoltage, and current directional relays are required. If power will also be provided to the utility grid, then in addition to the first two relays, overfrequency, underfrequency, and negative sequence relays will be needed. For larger units, the following additional protection relays are recommended:

  • Differential protection
  • Loss and excitation
  • Overspeed
  • Motoring protection
  • Stator and rotor protection
  • Overheating

For induction units, surge overspeed and internal short protection are recommended. It should be kept in mind that the protection levels suggested here are only guidelines; local utility requirements and site conditions must be taken into account.

To summarize, before the advent of cogeneration, facilities were only receivers of power; currently, they are partners in the power grid with utilities. It is the responsibility of both sides to ensure that the reliability and safety standards of the network are not compromised when connecting cogeneration systems.

Utility-Connected Systems

Increasingly, the most practical way to use renewable power is to connect it to a university or college building that is also served by its local utility. In this arrangement, the system provides a certain amount of the building’s electricity and the rest is provided through the utility. Other terms for this arrangement are grid-connected or utility-interactive systems.

When the system produces more than the building needs, the electricity can actually be fed back to the utility, gaining a credit on the building’s electric bill and ultimately earning money on the extra electricity produced. This approach is called net metering. An interconnection agreement needs to be signed with the utility company for facilitating connections of the renewable power system.

Utility-connected systems do not require many additional parts, though a device that can translate DC current into AC current is needed. This device, called an inverter, receives the DC current from the solar array and translates it into AC current, which is then fed to a distribution panel. Utility-connected systems can be connected either on the line side of the main distribution panel in the building or on the load side of the panel. In case the system is connected on the load side of the panel, the bus of the main distribution panel needs to be sized equal to the sum of the ratings of the breakers serving the bus.

Battery Storage Systems

Battery storage systems can be used in places where utility connected systems are not an option or if the facility generates more power than what is consumed at the facility. In this arrangement, all the electricity produced by the system is fed through a battery, which transfers electricity on when it is needed and stores it when it is not.

Battery systems require an additional component called a charge controller to regulate the quality of electricity flowing from the system to the battery. This charge controller can serve a dual purpose in channeling electricity to both the battery and a separate DC electrical load.

System Protection


Short-Circuit Faults

Electric current always follows the path of least resistance. What confines electricity in a conductor is the dielectric around the conductor. If the insulation between two conductors or a conductor and ground drops to zero, a large current is going to flow in the circuit. This is called short-circuit current, because the current has found a shorter path than the path through the load.

The short-circuit current can be as high as 10,000 times the rated current. Fault current can be destructive and cause equipment damage, fire, and personal injury. Short-circuit current magnitude is a function not of the load, but of the capacity of the power source and the length and size of the conductor. A water dam can serve as an analogy for potential short-circuit current. Normally, the water flow in a dam is dependent on the pipe size, but if the dam breaks, the water flow will depend only on the total water available in the dam, independent of the pipe size.

The available short-circuit current in an electrical system is explained in the following example. Consider a circuit where a 500-V, 10-kVA load is connected to the utility through two possible transformers to the utility system. The transformer choices are a 10-kVA unit with an impedance of 0.2 ohms and a 10,000-kVA unit with 0.02 ohms impedance. The load impedance is 25 ohms. Thus, for both transformers the normal-load current is 20 amperes.

If there is a short circuit at any point on the cable, the available current in each transformer will be different. Available fault current in the first transformer will be 2,500 amperes, whereas the second transformer will be 25,000 amperes. In the first case, the fuse must only be able to interrupt 2,500 amps, but in the second case the fuse must be able to interrupt 25,000 amps, since its available fault is higher.

There are four sources of short-circuit currents: the utility system, in-house synchronous generators, induction motors, and synchronous motors. The available fault from the utility is directly related to the size of the utility transformer. For a synchronous motor, the available fault current is four to five times the motor’s full-load current, and for an induction motor, it is two to four times the motor’s full-load current.

There are two types of faults: symmetrical and asymmetrical. A symmetrical fault is a three-phase fault, sometimes referred to as a bolted fault. Here it is assumed that all three-phase conductors are brought together simultaneously. About five percent of short-circuit failures are due to symmetrical faults. All other faults (e.g., line-to-ground, line-to-line, or line-to-line-to-ground faults) are referred to as asymmetrical faults. When the system is in a faulted condition, it can disrupt the transmission network in one or more of the following ways:

  • Allowing large currents to flow, which can damage equipment
  • Causing electrical arcing, which can start fires or damage equipment
  • Raising or lowering system voltage outside acceptable ranges
  • Causing a three-phase system to become unbalanced, which in turn causes three-phase equipment to operate improperly
  • Interrupting the flow of power

The protection system of a high-voltage electrical system is designed to safeguard against these disruptions. It works to detect and isolate faults, keeps as much of the system in operation as possible, restores the system as soon as possible, and discriminates between normal and abnormal system conditions so that protective devices will not operate unnecessarily.

There are three types of components in a protection system: fuses, relays, and circuit breakers. A fuse is a device that opens a circuit if an overload or short circuit occurs. It consists of a short, fusible link held under tension. When the current is increased beyond a certain point, the link will melt, and the spring will pull the contacts further apart, thus interrupting the current in the circuit. The main selection criteria for fuses are voltage rating, ampacity, and interrupting rating, to which the following guidelines apply:

  • The voltage rating of a fuse should always be equal to or greater than the system voltage.
  • The ampacity of the fuse should be equal to the rating of the load.
  • The interrupting capacity of the fuse should be equal to or greater than the available fault current.
  • The time-current characteristics of the fuse should be such that system selectivity is ensured.

Protective relays are used to minimize damage to electrical equipment by interrupting the power circuit during a fault. There are four types of protective relays: electromagnetic attraction, electromagnetic induction, thermal induction, and electronic. Protective relays must have the following characteristics:

  • Reliability: They may be idle for several years and then suddenly be required to operate quickly.
  • Selectivity: They must not respond to abnormal but harmless system conditions, such as sudden changes in load.
  • Sensitivity: They must be responsive enough to perform in every case required.
  • Speed: They must make decisions and respond quickly.

Circuit breakers are mechanical devices that are capable of breaking and reclosing a circuit under all conditions, even when the system is faulted and currents are great. Circuit breaking occurs when a mechanical latch is released, which enables a coiled spring or a weight to open the contacts.

Selection of System Protective Devices

In institutional power systems, such as university campuses, circuit breakers have been used for applications requiring complex relaying schemes or high continuous currents. However, for most applications a choice of either circuit breakers or power fuses is available. Fuses have achieved widespread use in such applications because of their simplicity, economy, fast response characteristics, and freedom from maintenance.

Circuit breakers and their associated relays are commonly used where the reclosing capability of the circuit breaker is an advantage, such as applications involving overhead lines, which have a relatively high incidence of transient or temporary faults. This reclosing feature is neither useful nor desirable in institutional power systems where the conductors are arranged in cable trays, enclosed in conduits or bus ducts, or are underground. The incidence of faults in these systems is low, and the rare faults that do occur are not transient and result in significant damage that would only be exacerbated by an automatic reclosing operation.

The relaying associated with circuit breakers is available in various degrees of sophistication and complexity. Systems requiring differential protection, reverse-power relaying, or non-current magnitude tripping of the protective device typically require circuit breakers. However, the size of transformers normally associated with institutional power systems generally does not warrant such sophisticated protection. Indeed, many users find that the complexity of such protective relaying, with its requirement for periodic testing and recalibration, is a distinct disadvantage.

Circuit breakers also are used in applications requiring a very high (above 720 amperes) continuous current-carrying capability. Although they may be an advantage in some cases, a higher degree of service continuity can be achieved with less expensive power fuses by subdividing the system into a number of discrete segments, with the result that a fault on one segment of the system will affect fewer loads. This high degree of segmentation also allows the use of smaller transformers located strategically throughout the university’s electrical distribution system, eliminating the need for the long, high-ampacity secondary conductors that are required where fewer larger and widely separated transformers are used.

Where high continuous current-carrying capability is not required and reclosing or sophisticated relaying is not justified, as in medium-voltage and institutional power systems, power fuses offer a number of advantages. Power fuses are simple to install and require no maintenance of any kind; even after years of neglect, power fuses will operate properly. Recalibration is neither required nor possible; hence, elaborate testing procedures are not needed, eliminating the possibility that a carefully engineered coordination plan will be disturbed accidentally. Power fuses, unlike circuit breakers, provide fault protection for the system without depending on a source of control power, such as storage batteries and their chargers. Such batteries may be found to be completely discharged and thus incapable of tripping the circuit breaker should a fault occur. In addition, for high-magnitude faults, power fuses have inherently faster response characteristics than circuit breakers, permitting more rapid removal of faults from the system.

Types and Symptoms of Failures

The major cause of electrical failures is the breakdown of insulation. Insulation breakdown is caused by dirt, high ambient temperature, oil leakage, internal failure, overload, high-voltage surges, corona, ferroresonance, or flashover. Other causes are absorption of moisture and dust into the cores, excessive vibration and aging.

Dirt: Moisture or condensation of airborne chemicals causes electrical leakage, which in turn causes tracking and eventual flashover.

High Ambient Temperature: A 10°F to 15°F overheat above the rated temperature will cause insulation to become brittle, deteriorate, and shorten the useful life of equipment by half.

Oil Leakage: Excessive loss of oil or compound will result in equipment loss. Once the insulation material is lost, a void is created and dielectric values will be drastically reduced.

Internal Failure: Loose connections may result from mechanical forces that are created by surges, overloads, and vibration. Loosened terminals, fuse clips, and live part connections in the switch will create excessive heat and thereby accelerate further deterioration of the system.

Overload: Overload produces excessive heat that decreases the useful life of the equipment.

High-Voltage Surge: High-voltage surges are a serious problem for most utility companies. Surges create flexing and physical displacement of component parts, which in turn leads to loose connections and overheating. Surges produce stability problems that may lead to resonant failures, and also can cascade into the secondary side and create failures.

Corona: Corona is a discharge caused by electric stresses, which in turn can be produced by high electric fields, dirt, moisture, sharp bends in cable, severe weather conditions, and faulty design. It can be detected by its secondary symptoms: ozone odor, radio and television interference, visible pulsating of a blue or green color, crackling noises, and the production of a gray powder on the unshielded cable.

Ferroresonance: Ferroresonance is usually caused by a single-phase opening where no secondary load exists on the transformer. The inductance of the transformer and the capacitance of the cable can form a series-resonant circuit and create instantaneous voltage up to 50 times the normal rating, which can give rise to a violent explosion in cables and transformers. The following are indications of ferroresonance:

  • Loud humming and vibration of a transformer
  • Sparkover of arresters on open phases yet to be closed
  • Overvoltage breakdown failure of cables, transformers, and arresters
  • Motors running backward

Ferroresonance can be prevented by the following:

  • Grounding neutral on all transformer wye windings
  • Energizing transformers with the same load
  • Energizing cables first, then the transformer
  • Installing fuses both at the cable entrance and at the transformer
  • Energizing all three phases simultaneously

Fiashover: All of the failures mentioned thus far will eventually result in flashover if corrective action is not taken. The usual trigger for flashover is dirt and moisture over the insulation. As an arc is established, heat is generated and starts a cascade effect.



Test Instruments

Electrical test instruments are the tools used to perform maintenance on power systems. For low voltages, the multimeter and amprobe are used. Voltage and resistance are measured with a multimeter, whereas current is measured with an amprobe. For high-voltage systems, the following instruments are used:

  • Infrared Detector: The use of infrared units can greatly enhance visual inspection, because problems such as overloads, imbalances, loose connections, and dirty cores in a dry transformer can be readily located.
  • Megger: A megger, whether hand or motor driven, will give a quick analysis of the integrity of the insulation on a cable or in a transformer. The 2,500-V megger is effective for troubleshooting cables, motors, and transformers.
  • Hipot Tester: A hipot tester normally is used when the condition of cable cannot be determined with a megger. Although the hipot tester has the capability to test up to 80 kV, tests that are up to two times the operational voltage are usually recommended. Great care must be taken with this instrument to avoid damaging the cable by imposing excessively high stress voltages.
  • Phase Meter: A phase meter is used to test fuses or to phase two feeds to one another. It is also used for draining capacitance from a system during a shutdown and for proving that the system is de-energized prior to the attachment of ground connections.
  • Glow Stick: A glow stick is an excellent way to test for fault potential on an unshielded cable. It is of no value for testing a blown fuse or for discharging a system.
  • Dielectric Tester: A dielectric tester gives a quick analysis of the dielectric value of oil. Moisture, pH, and other tests also should be considered when using this instrument. A two-year test program on all liquid-filled apparatuses is recommended.


The need to accurately measure electrical energy became critical after the energy crisis of the 1970s. The instrument for measuring electrical energy is the kilowatt hour (kWh) meter, which measures cumulative energy consumption over a period of time. Another useful measurement is kilowatt demand (kWD), which signifies the maximum power demand within a time period. Utilities use demand costs as part of the total electric charge, so by measuring power demand, the institution can analyze consumption patterns for possible reductions. In addition, the difference between peak demand and the substation rating indicates the available spare capacity, which is useful when considering future distribution expansion.

For low-voltage systems (less than 150 amperes), a kWh meter is connected directly to the service. For high-voltage systems and larger currents, potential transformers (PTs) and current transformers (CTs) are used. PTs have the same primary voltage as the system but have a secondary voltage of 120 V. CTs are shaped like doughnuts and are placed around the power conductor. Because CTs are constant current sources, if the CT circuit is opened when energized, an explosion can result from high voltages.

Electric meters are subject to drift, so they should be periodically tested and calibrated. The magnitude of service and the critical importance of the data will determine how often they should be calibrated.

Use of Capacitors for Power Factor Correction

Power factor is an important value in load consideration and measurement. AC was adopted principally to take advantage of transformers that do not operate with direct current and also helped simplify motor design. At the same time, problems were introduced by the presence of inductive reactance in the circuit and reactive power required by motor loads. Because of the reactive power, principally in motors but to some extent in other loads, the current lags in time relative to the voltage. Therefore, more current is required to provide a given amount of power. The power factor is the quantity by which the apparent power must be multiplied to obtain the active power of the circuit. There is no way to eliminate this component of current, but it can be neutralized by adding another load to the circuit in the form of capacitors. Capacitors can be located at the loads, in the substations, or on the lines. Power factor correction on the lines generally is less costly.

Additional Resources


Edison Electric Institute, 1957. Underground Systems Reference Book. New York:EEI.

Electrical School, Glossary of Electrical Terms,

Fink, D. G., and J. M. Carroll. 1968. Standard Handbook for Electrical Engineers, 10th edition. New York: McGraw-Hill.

Glenn, D. J., and C. J. Cook. October 1984.  “A New Fault Interrupting Device for Improved Medium Voltage System and Equipment Protection.” IEEE Transactions on Industry Applications 1A:21, Issue 5, 1324-1332.

Mason, C. R. 1967. The Art and Science of Protective Relaying. New York: John Wiley & Sons.

Miller, H. N. 1990. DC Hypot Testing of Cables, Transformers, and Rotating Machinery. Chicago: Associated Research, Inc., Manual 16086.

Qayoumi, Mohammad H. 1989. Electrical Distribution and Maintenance. Alexandria, VA: APPA.

Qayoumi, Mohammad H. 1996. Electrical Systems. New York: Upward Publishing.

Turley, S. Q. October 1966. “Ferroresonance Oversimplified.” Transmission & Distribution, 36-40.

Viermerster, P. 1961. The Lightning Book. New York: Doubleday.

Westinghouse Corporaton, 1965. Electrical Utility Engineering Reference Book, Vol 3:—Distribution Systems. Pittsburgh, PA: Westinghouse.

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