Hierarchical Voltage Levels

The overall concept of a power delivery system layout that has evolved to best handle these needs and “truths” is one of hierarchical voltage levels as shown in Figures 2.2 and 2.3. As power is moved from generation (large bulk sources) to consumer (small demand amounts) it is first moved in bulk quantity at high voltage - this makes particular sense since there is usually a large bulk amount of power to be moved out of a large generating plant. As power is dispersed throughout the service territory, it is gradually moved down to lower voltage levels, where it is moved in ever smaller amounts (along more separate paths) on lower capacity equipment until it reaches the consumers. The key element is a “lower voltage and split” concept.

Thus, in Figure 2.3, the 3 kW used by a particular consumer -- Mrs. Watts at 412 Oak Street in Metropolis City - might be produced at a 800 MW power plant more than three hundred miles to the north. Her power is moved as part of a 750 MW block of wholesale from plant to city on a 345 kV transmission line, to a switching substation. Here, the voltage is lowered to 138 kV through a 345 to 138 kV transformer, and immediately after that, this large block is split into five separate smaller portions in the switching substation’s bus work. Each of these five parts, roughly 150 MW each, is routed onto a transmission line leaving that substation.

Figure 2.2 A power system is structured in a hierarchical manner with various voltage levels. A key concept is “lower voltage and split” which is done from three to five times during the course of power flow from generation to consumer.

Now part of one of these smaller blocks of power, Mrs. Watts’s electricity is routed to her side of Metropolis on a 138 kV transmission line that snakes 20 miles through the northern part of the city. Ultimately this line connects to another switching substation on the south side of the city. Along the way, it feeds power to several distribution substations along its route,⁴ among which it feeds 40 MW into the particular substation that serves Mrs. Watts’s neighborhood as well as others around that. Here, her power is run through a 138-kV to 12.47kV distribution transformer. At the low side of that substation transformer, at 12.47 kV (the primary distribution voltage) the 40 MW is split into six parts, each about 7 MW, with each 7 MVA part routed onto a different distribution feeder. Mrs. Watts’s power flows along one particular feeder for two miles, until it gets to within a few hundred feet of her home. Here, a much smaller amount of power, 50 kVA (sufficient for perhaps ten homes), is routed to a service transformer, one of several hundred scattered up and down the length of the feeder.

Once on the service transformer Mrs. Watts's power and that of her neighbors is lowered to utilitization voltage, the voltage at which the utility’s customers will use the power. In this case that is 120/240 volts (208 V phase to phase). As it emerges, from the service transformer, her power is routed onto the secondary system, operating at that 120/240 volt level (250/416 volts in Europe and many other countries). The secondary wiring splits the 50 kVA into small blocks of power, each about 5 kVA, and routes one of these to Mrs. Watts’s home along a secondary conductor to her service drops - the wires leading directly to her house.

Over the past one hundred years, this hierarchical system structure has proven a most effective way to move and distribute power from a few large generating plants to a widely dispersed consumer base. Neglecting light variations in design and operating practice from one utility to another, all power delivery systems are like this. The key element in this structure is the “reduce voltage and split” function - a splitting of the power flow being done simultaneously with a reduction in voltage. Usually, this happens between three and five times as power makes its way from generator to consumers.

The (Wholesale) Transmission Level

The transmission system is a network of three-phase lines operating at voltages generally between 115 kV and 765 kV. Capacity of each line is between 50 MVA and 2,000 MVA. The term “network” means that there is more than one electrical path between any two points in the system (Figure 2.5). Networks are laid out in this manner for reasons of reliability and operating flow--if any one element (line) fails, there is an alternate route and power flow is (hopefully) not interrupted.

In addition to their function in moving power, portions of the transmission system, the largest elements, namely its major power delivery lines, are designed, at least in part, for stability needs. The transmission grid provides a strong electrical tie between generators, so that each can stay synchronized with the system and with the other generators. This arrangement allows the system to operate and to function evenly as the load fluctuates and to pick up load smoothly if any generator fails - what is called stability of operation. A good deal of the equipment put into transmission system design, and much of its cost, is for these stability reasons, not solely or even mainly, for moving power.

Figure 2.5 A network is an electrical system with more than one path between any two points, meaning that (if properly designed) it can provide electrical service even if any one element fails.

The Sub-transmission Level

The sub-transmission lines in a system take power from the transmission switching stations or generation plants and deliver it to substations along their routes. A typical sub-transmission line may feed power to three or more substations. Often, portions of the transmission system, bulk power delivery lines, lines designed at least in part for stability as well as power delivery needs to do this too. The distinction between transmission and sub-transmission lines becomes rather blurred.

Normally, sub-transmission lines are in the range of capacity of 30 MVA up to perhaps 250 MVA, operating at voltages from 34.5 kV to as high as 230 kV. With occasional exceptions, sub-transmission lines are part of a network grid - they are part of a system in which there is more than one route between any two points. Usually, at least two sub-transmission routes flow into any one substation, so that feed can be maintained if one fails.⁶

The Substation Level

Substations, the meeting point between the transmission grid and the distribution feeder system, are where a fundamental change takes place within most T&D systems. The transmission and sub-transmission systems above the substation level usually form a network, as discussed above, with more than one power flow path between any two parts. But from the substation on to the consumer, arranging a network configuration would simply be prohibitively expensive. Thus, most distribution systems are radial - there is only one path through the other levels of the system.

Typically, a substation occupies an acre or more of land on which the necessary substation equipment is located. Substation equipment consists of high and low voltage racks and busses for the power flow, circuit breakers for both the transmission and distribution level, metering equipment, and the “control house,” where the relaying, measurement, and control equipment is located. But the most important equipment, what gives this substation its capacity rating, are the substation transformers. These transformers convert the incoming power from transmission voltage levels to the lower primary voltage for distribution.

Individual substation transformers vary in capacity, from less than 10 MVA to as much as 150 MVA. They are often equipped with tap-changing mechanisms and control equipment to vary their winding ratio so that they maintain the distribution voltage within a very narrow range, regardless of larger fluctuations on the transmission side. The transmission voltage can swing by as much as 5%, but the distribution voltage provided on the low side of the transformer stays within a narrow band, perhaps only ± .5%.

⁶ Radial feed - only one line - is used in isolated, expensive, or difficult transmission situations, but for reliability reasons is not recommended.

Very often, a substation will have more than one transformer. Two is a common number, four is not uncommon, and occasionally six or more are located at one site. Having more than one transformer increases reliability. In an emergency, a transformer can handle a load much over its rated load for a brief period (e.g., perhaps up to 140% of rating for up to four hours). Thus, the T&D system can pick up the load of the outaged portions during brief repairs and in emergencies.

Equipped with one to six transformers, substations range in “size” or capacity from as little as five MVA for a small, single-transformer substation, serving a sparsely populated rural area, to more than 400 MVA for a truly large six-transformer station, serving a very dense area within a large city.

Often T&D planners will speak of a transformer unit, which includes the transformer and all the equipment necessary to support its use - “one fourth of the equipment in a four-transformer substation.” This is a much better way of thinking about and estimating cost for equipment in T&D plans. While a transformer itself is expensive (between $50,000 and $1,000,000); the buswork, control, breakers, and other equipment required to support its use can double or triple that cost. Since that equipment is needed in direct proportion to the transformer’s capacity and voltage, and since it is needed only because a transformer is being added, it is normal to associate it with the transformer as a single planning unit. Add the transformer and add the other equipment along with it.

Substations consist of more equipment and involve more costs than just the electrical equipment. The site has to be purchased and prepared. Preparation is not trivial. The site must be excavated, a grounding mat - wires running under the substation to protect against an inadvertent flow during emergencies - laid down, and foundations and control ducting for equipment must be installed. Transmission towers to terminate incoming transmission must be built. Feeder getaways - ducts or lines to bring power out to the distribution system - must be added.

The Feeder Level

Feeders, typically either overhead distribution lines mounted on wooden poles or underground buried or ducted cable sets, route the power from the substation throughout its service area. Feeders operate at the primary distribution voltage. The most common primary distribution voltage in use throughout North America is 12.47 kV, although anywhere from 4.2 kV to 34.5 kV is widely used. Worldwide, there are primary distribution voltages as low as 1.1 kV and as high as 66 kV. Some distribution systems use several primary voltages - for example 23.9 kV, 13.8 kV and 4.16 kV.

A feeder is a small transmission system in its own right, distributing between 2 MVA to more than 30 MVA, depending on the conductor size and the distribution voltage level. Normally between two and 12 feeders emanate from any one substation, in what has been called a dendrillic configuration - repeated branching into smaller branches as the feeder moves out from the substation toward the consumers. In combination, all the feeders in a power system constitute the feeder system (Figure 2.6). An average substation has between two and eight feeders, and can vary between one and forty feeders.

Figure 2.6 Distribution feeders route power away from the substation, as shown (in idealized form - configuration is never so evenly symmetric in the real world) for two substations. Positions of switches make the system electrically radial, while parts of it are physically a network. Shown here are two substations, each with four feeders.

The main, three-phase trunk of a feeder is called the primary trunk and may branch into several main routes, as shown in the diagram on the next page. These main branches end at open points where the feeder meets the ends of other feeders - points at which a normally open switch serves as an emergency tie between two feeders.

Additionally, normally closed switches in several switchable elements will divide each feeder. During emergencies, segments can be re-switched to isolate damaged sections and route power around outaged equipment to consumers who would otherwise have to remain out of service until repairs were made.

By definition, the feeder consists of all primary voltage level segments between the substations and an open point (switch). Any part of the distribution level voltage lines - three-phase, two-phase, or single-phase - that is switchable is considered part of the primary feeder. The primary trunks and switchable segments are usually built using three phases. The largest size of distribution conductor (typically this is about 500-600 MCM conductor, but a conductor over 1,000 MCM is not uncommon, and one of the authors designed and built a feeder with a 2,000 MCM conductors) being used for reasons other than just maximum capacity (e.g., contingency switching needs). Often a feeder has excess capacity because it needs to provide back up for other feeders during emergencies.

The vast majority of distribution feeders used worldwide and within the United States are overhead construction, wooden pole with wooden crossarm or post insulators. Only in dense urban areas, or in situations where esthetics are particularly important, can the higher cost of underground construction be justified. In this case, the primary feeder is built from insulated cable, which is pulled through concrete ducts that are first buried in the ground. Underground feeder costs are three to ten times that of overhead costs.

Many times, however, the first several hundred yards of an overhead primary feeder are built underground even if the system is overhead. This underground portion is used as the feeder get-away. Particularly at large substations, the underground get-away is dictated by practical necessity, as well as by reliability and esthetics. At a large substation, ten or twelve 3-phase, overhead feeders leaving the substation mean from 40 to 48 wires hanging in mid-air around the substation site, with each feeder needing the proper spacing for electrical insulation, safety, and maintenance.

One significant aging infrastructure issue is that at many large-capacity substations in a tight location, there is simply not enough overhead space for enough feeders to be routed out of the substation. Even if there is, the resulting tangle of wires looks unsightly, and perhaps most importantly, is potentially unreliable. One broken wire falling in the wrong place can disable a lot of power delivery capability. The solution to this dilemma is the underground feeder get-away, usually consisting of several hundred yards of buried, ducted cable that takes the feeder out to a riser pole, where it is routed above ground and connected to overhead wires. Very often, this initial underground link sets the capacity limit for the entire feeder. The underground cable ampacity is the limiting factor for the feeder's power transmission.

The Lateral Level

Laterals are short stubs or line-segments that branch off the primary feeder and represent the final primary voltage part of the power's journey from the substation to the consumer. A lateral is directly connected to the primary trunk and operates at the same nominal voltage. A series of laterals tap off the primary feeder as it passes through a community, each lateral routing power to a few dozen homes.

Normally, laterals do not have branches, and many laterals are only one or two-phase. All three phases are used only if a relatively substantial amount of power is required, or if three-phase service must be provided to some of the consumers. Normally, single and two-phase laterals are arranged to tap alternately into different phases on the primary feeder. An attempt by the Distribution Planning Engineer to balance the loads as closely as possible is shown below.

Typically, laterals deliver from as little as 10 kVA for a small single-phase lateral, to as much as 2 MVA. In general, even the largest laterals use small conductors (relative to the primary size). When a lateral needs to deliver a great deal of power, the planner will normally use all three phases, with a relatively small conductor for each, rather than employ a single-phase and use a large conductor. This approach avoids creating a significant imbalance in loading at the point where the lateral taps into the primary feeder. Power flow, loadings and voltage are maintained in a more balanced state if the power demands of a “large lateral” are distributed over all three phases.

Laterals (wooden poles) are built overhead or underground. Unlike primary feeders and transmission lines, single-phase laterals are sometimes buried directly. In this case, the cable is placed inside a plastic sheath (that looks and feels much like a vacuum cleaner hose). A trench is dug, and the sheathed cable is unrolled into the trench and buried. Directly buried laterals are no more expensive than underground construction in many cases.

The Service Transformers

Service transformers lower voltage from the primary voltage to the utilization or consumer voltage, normally 120/240-volt two-leg service in most power systems throughout North America. In overhead construction, service transformers are pole mounted and single-phase, between 5-kVA and 166 -kVA capacity. There may be several hundred scattered along the trunk and laterals of any given feeder; since power can travel efficiently only up to about 200 feet at utilization voltage, there must be at least one service transformer located reasonably close to every consumer. In underground areas, service transformers may be located in underground vaults, or at ground level (pad-mounted).

Passing through these transformers, power is lowered in voltage once again, to the final utilization voltage (120/240 volts in the United States) and routed to the secondary system or directly to the consumers. In cases where the system is supplying power to large commercial or industrial consumers, or the consumer requires three-phase power, between two and three transformers may be located together in a transformer bank, and be interconnected in such a way as to provide multi-phase power. Several different connection schemes are possible for varying situations.

Padmount and vault-type service transformers provide underground service, as opposed to overhead pole-mounted service. The concept is identical to overhead construction, with the transformer and its associated equipment changed to accommodate incoming and outgoing lines that are underground.

The Secondary and Service Level

Secondary circuits fed by the service transformers route power at utilization voltage within very close proximity to the consumer. Usually this is an arrangement in which each transformer serves a small radial network of utilization voltage secondary and service lines. These lead directly to the meters of consumers in the immediate vicinity.

At most utilities, the layout and design of the secondary level is handled through a set of standardized guidelines and tables. Engineering technicians use these and clerks to produce work orders for the utilization voltage level equipment. In the United States, the vast majority of this system is single-phase. In European systems, much of the secondary is 3-phase, particularly in urban and suburban areas.

What is Transmission and What is Distribution?

Definitions and nomenclature defining “transmission” and “distribution” vary greatly among different countries, companies, and power systems. Generally, four types of distinction between the two are made, only three of which are dealt with it this book:

Generally, the last three definitions apply simultaneously since in most utility systems any transmission above 34.5 kV is configured as a network and does not feed service transformers directly. On the other hand, all distribution is radial, built of only 34.5 kV or below, and does feed service transformers. Substations - the meeting places of transmission lines (incoming) and distribution lines (outgoing) - are often included in one or the other category, and sometimes are considered as separate entities.

Transmission and Distribution Lines

By far the most omnipresent part of the power distribution system is the portion devoted to actually moving the power flow from one point to another. Transmission lines, sub-transmission lines, feeders, laterals, secondary and service drops, all consist of electrical conductors, suitably protected by isolation (transmission towers, insulator strings, and insulated wrappings) from voltage leakage and ground contact. It is this conductor that carries the power from one location to another.

Electrical conductors are available in various capacity ranges, with capacity generally corresponding to the metal cross section (other things being equal, thicker wire carries more power). Conductors can be all steel (rare, but used in some locations where winter ice and wind loadings are quite severe), all aluminum, or copper, or a mixture of aluminum and steel. Underground transmission can use various types of high-voltage cable. Line capacity depends on the current-carrying capacity of the conductor or the cable, the voltage, the number of phases, and constraints imposed by the line's location in the system.

The most economical method of handling a conductor is to place it overhead, supported by insulators on wooden poles or metal towers suitably clear of interference or contact with persons or property. However, underground construction, while generally more costly, avoids esthetic intrusion of the line and provides some measure of protection from weather. It also tends to reduce the capacity of a line slightly due to the differences between underground cable and overhead conductor. Suitably wrapped with insulating material in the form of underground cable, the cable is placed inside concrete or metal ducts or surrounded in a plastic sheath.

Transmission/sub-transmission lines are always 3-phase. There are three separate conductors for the alternating current, sometimes with a fourth neutral (un-energized) wire. Voltage is measured between phases. A 12.47 kV distribution feeder has an alternating current voltage (RMS) of 12,470 volts as measured between any two phases. Voltage between any phase and ground is 7,200 volts (12.47 divided by the square root of three). Major portions of a distribution system - trunk feeders - are as a rule built as three-phase lines, but lower-capacity portions may be built as either two-phase, or single-phase.⁷

Regardless of type or capacity, every electrical conductor has impedance (a resistance to electrical flow through it) that causes voltage drop and electrical losses whenever it is carrying electric power. Voltage drop is a reduction in the voltage between the sending and receiving ends of the power flow. Losses are a reduction in the net power, and are proportional to the square of the power. Double the load and the losses increase by four. Thus, 100 kilowatts at 120 volts might go in one end of a conductor, only to emerge at the other as 90 kilowatts at 114 volts at the other end. Both voltage drop and losses vary in direct relation to load - within very fine limits if there is no load, there are no losses or voltage drop. Voltage drop is proportional to load. Double the load and voltage drop doubles. Losses are quadratic, however. Double the load and losses quadruple.

⁷ In most cases, a single-phase feeder or lateral has two conductors: the phase conductor and the neutral.

Transformers

At the heart of any alternating power system are transformers. They change the voltage and current levels of the power flow, maintaining (except for a very small portion of electrical losses), the same overall power flow. If voltage is reduced by a factor of ten from the high to low side, then Current is multiplied by ten, so that their overall product (Voltage times Current equals Power) is constant in and out.

Transformers are available in a diverse range of types, sizes, and capacities. They are used within power systems in four major areas:

1. At power plants, where power which is minimally generated at about 20,000 volts is raised to transmission voltage (100,000 volts or higher),

2. At switching stations, where transmission voltage is changed (e.g., from 345,000 volts to 138,000 volts before splitting onto lower voltage transmission lines),

3. At distribution substations, where incoming transmission-level voltage is reduced to distribution voltage for distribution (e.g., 138 kV to 12.47 kV),

4. And at service transformers, where power is reduced in voltage from the primary feeder voltage to utilization level (12.47 kV to 120/240 volts) for routing into consumers’ homes and businesses.

Larger transformers are generally built as three-phase units, in which they simultaneously transform all three phases. Often these larger units are built to custom or special specifications, and can be quite expensive - over $3,000,000 per unit in some cases. Smaller transformers, particularly most service transformers, are single-phase - it takes three installed side by side to handle a full three-phase line’s power flow. They are generally built to standard specifications and bought in quantity.

Transformers experience two types of electrical losses - no-load losses (often called core, or iron, losses) and load-related losses.

No-load losses are electrical losses inherent in operating the transformer -due to its creation of a magnetic field inside its core. They occur simply because the transformer is connected to an electrical power source. They are constant, regardless of whether the power flowing through the transformer is small or large. No-load losses are typically less than one percent of the nameplate rating. Only when the transformer is seriously overloaded, to a point well past its design range, will the core losses change (due to magnetic saturation of the core).

Load-related losses are due to the current flow through the transformer's impedance and correspond very directly with the level of power flow. Like those of conductors and cables they are proportional to current squared or quadrupling whenever power flow doubles. The result of both types of losses is that a transformer's losses vary as the power transmitted through it varies, but always at or above a minimum level set by the no-load losses.

Switches

Occasionally, it is desirable to be able to vary the connection of line segments within a power delivery system, particularly in the distribution feeders. Switches are placed at strategic locations so that the connection between two segments can be opened or closed. Switches are planned to be normally closed (NC) or normally open (NO), as was shown in Figure 2.6.

Switches vary in their rating (how much current they can vary) and their load break capacity (how much current they can interrupt or switch off), with larger switches being capable of opening a larger current. They can be manually, automatically, or remotely controlled in their operation.

Protection

When electrical equipment fails, for example if a line is knocked down during a storm, the normal function of the electrical equipment is interrupted. Protective equipment is designed to detect these conditions and isolate the damaged equipment, even if this means interrupting the flow of power to some consumers. Circuit breakers, sectionalizers, and fused disconnects, along with control relays and sensing equipment, are used to detect unusual conditions and interrupt the power flow whenever a failure, fault, or other unwanted condition occurs on the system.

These devices and the protection engineering required to apply them properly to the power system are not the domain of the utility planners and will not be discussed here. Protection is vitally important, but the planner is sufficiently involved with protection if he or she produces a system design that can be protected within standards, and if the cost of that protection has been taken into account in the budgeting and planning process. Both of these considerations are very important.

Protection puts certain constraints on equipment size and layout - for example, in some cases a very large conductor is too large (because it would permit too high a short circuit current) to be protected safely by available equipment and cannot be used. In other cases, long feeders are too long to be protected (because they have too low a short circuit current at the far end). A good deal of protective equipment is quite complex, containing sensitive electro-mechanical parts (many of which move at high speeds and in a split-second manner), and depending on precise calibration and assembly for proper function. As a result, the cost of protective equipment and control and the cost of its maintenance are often significant. Differences in protection cost can make the deciding difference between two plans.

Voltage Regulation

Voltage regulation equipment includes line regulators and line drop compensators, as well as tap changing transformers. These devices vary their turns-ratio (ratio of voltage in to voltage out) to react to variations in voltage drop. If voltage drops, they raise the voltage; if voltage rises, they reduce it to compensate. Properly used, they can help maintain voltage fluctuation on the system within acceptable limits, but they can only reduce the range of fluctuation, not eliminate it altogether.

Capacitors

Capacitors are a type of voltage regulation equipment. By correcting power factor they can improve voltage under many heavy loads (hence large voltage drop) cases. Power factor is a measure of how well voltage and current in an alternating system are in step with one another. In a perfect system, voltage and current would alternately cycle in conjunction with one another - reaching a peak, then reaching a minimum, at precisely the same times. But on distribution systems, particularly under heavy load conditions, current and voltage fall out of phase. Both continue to alternate 60 times a second, but during each cycle voltage may reach its peak slightly ahead of current - there is a slight lag of current versus voltage, as shown in Figure 2.7.

It is the precise, simultaneous peaking of both voltage and current that delivers maximum power. If out of phase, even by a slight amount, effective power drops, as does power factor - the ratio of real (effective) power to the maximum possible power, if voltage and current were locked in step.

Power engineers refer to a quantity called VARs (Volt-Amp Reactive) that is caused by this condition. Basically, as power factors worsen (as voltage and current fall farther apart in terms of phase angle) a larger percentage of the electrical flow is VARs, and a smaller part is real power. The frustrating thing is that the voltage is still there, and the current is still there, but because of the shift in their timing, they produce only VARS, not power. The worse the power factor, the higher the VAR content. Poor power factor creates considerable cost and performance consequences for the power system: a large conductor is still required to carry the full level of current even though power delivery has dropped. And because current is high, the voltage drop is high, too, further degrading quality of service.

Unless one has worked for some time with the complex variable mathematics associated with AC power flow analysis, VARs are difficult to picture. A useful analogy is to think of VARs as “electrical foam.” If one tried to pump a highly carbonated soft drink through a system of pipes, turbulence in the pipes, particularly in times of high demand (high flow) would create foam. The foam would take up room in the pipes, but contribute little value to the net flow - the equivalent of VARs in an electrical system.

Poor power factor has several causes. Certain types of loads create VARs -loads that cause a delay in the current with respect to voltage as it flows through them. Among the worst offenders are induction motors - particularly small ones as almost universally used for blowers, air conditioning compressors, and the powering of conveyor belts and similar machinery. Under heavy load conditions, voltage and current can get out of phase to the point that the power factor can drop below 70%. Additionally, transmission equipment itself can often create this lag and “generate” a poor power factor.

Figure 2.7 Current and voltage in phase deliver maximum power (left). If current and voltage fall out of phase (right), actual power delivered drops by very noticeable amounts -- the power factor falls.

Capacitors correct the poor power factor. They “inject” VARs into a T&D line to bring power factor close to 1.0, transforming VAR flow back into real power flow, regaining the portion of capacity lost to poor power factor. Capacitors can involve considerable cost depending on location and type. They tend to do the most good if put on the distribution system, near the consumers, but they cost a great deal more in those locations than if installed at substations.

Transmission Costs

Transmission line costs are based on a per-mile cost and a termination cost at either end of the line associated with the substation at which it is terminated. Costs can run from as low as $50,000/mile for a 46 kV wooden pole sub-transmission line with perhaps 50 MVA capacity ($1 per kVA-mile) to over $1,000,000 per mile for a 500 kV double circuit construction with 2,000 MVA capacity ($.5/kVA-mile).

Substation Costs

Substation costs include all the equipment and labor required to build a substation, including the cost of land and easements/ROW. For planning purposes, substations can be thought of as having four costs:

1. Site cost - the cost of buying the site and preparing it for a substation, including the cost of all legal work required to gain permissions and licenses (this can sometimes exceed the cost of the land).

2. Transmission cost - the cost of terminating the incoming sub-transmission lines at the site.

3. Transformer cost - the transformer and all metering, control, oil spill containment, fire prevention, cooling, noise abatement, and other related equipment, along with buswork, switches, metering, relaying, and breakers associated with this type of transformer, and their installation.

4. Feeder buswork/Get-away costs - the cost of beginning distribution at the substation, includes getting feeders out of the substation.

To expedite planning, estimated costs of feeder buswork and get-aways are often folded into the transformer costs. The feeders to route power out of the substation are needed in conjunction with each transformer and in direct proportion to the transformer capacity installed, so that their cost is sometimes considered together with the transformer as a single unit. Regardless, the transmission, transformer, and feeder costs can be estimated fairly accurately for planning purposes.

Cost of land is another matter entirely. Site and easements or ROW into a site have a cost that is a function of local land prices, which vary greatly depending on location and real estate markets. Site preparation includes the cost of preparing the site which includes grading, grounding mat, foundations, buried ductwork, control building, lighting, fence, landscaping, and an access road.

Substation costs vary greatly depending on type, capacity, local land prices and other variable circumstances. In rural settings where load density is quite low and minimal capacity is required, a substation may involve a site of only several thousand square feet of fenced area. This single area includes a single incoming transmission line (69 kV), one 5 MVA transformer; fusing for all fault protection; and all “buswork” built with wood poles and conductor, for a total cost of perhaps no more than $90,000. The substation would be applied to serve a load of perhaps 4 MW, for a cost of $23/kW. This substation in conjunction with the system around it would probably provide service with about ten hours of service interruptions per year under average conditions.

However, a typical substation built in most suburban and urban settings would be fed by two incoming 138 kV lines feeding two 40 MVA, 138 kV to 12.47 kV transformers. These transformers would each feed a separate low side (12.47 kV) bus, each bus with four outgoing distribution feeders of 9 MVA peak capacity each, and a total cost of perhaps $2,000,000. Such a substation’s cost could vary from between about $1.5 million and $6 million, depending on land costs, labor costs, the utility equipment and installation standards, and other special circumstances. In most traditional vertically integrated, publicly regulated electric utilities, this substation would have been used to serve a peak load of about 60 MVA (75% utilization of capacity), meaning that at its nominal $2,000,000 cost works out to $33/kW. In a competitive industry, with tighter design margins and proper engineering measures taken beforehand, this could be pushed to a peak loading of 80 MVA (100% utilization, $25/kW). This substation and the system around it would probably provide service with about two to three hours of service interruptions per year under “normal,” average conditions.

Feeder System Costs

The feeder system consists of all the primary distribution lines, including three-phase trunks and their lateral extensions. These lines operate at the primary distribution voltage - 23.9 kV, 13.8 kV, 12.47 kV, 4.16kV or whatever - and may be three-, two-, or single-phase construction as required. Typically, the feeder system is also considered to include voltage regulators, capacitors, voltage boosters, sectionalizers, switches, cutouts, fuses, and any intertie transformers (required to connect feeders of different voltage at tie points - for example: 23.9 and 12.47 kV) that are installed on the feeders (not at the substations or at consumer facilities).

As a rule of thumb, construction of three-phase overhead, wooden pole crossarm type feeders using a normal, large conductor (about 600 MCM per phase) at a medium distribution primary voltage (e.g., 12.47 kV) costs about $150,000/mile. However, cost can vary greatly due to variations in labor, filing and permit costs among utilities, as well as differences in design standards, and terrain. Where a thick base of topsoil is present, a pole can be installed by simply auguring a hole for the pole. In areas where there is rock close under the surface, holes have to be jack-hammered or blasted, and costs go up accordingly. It is generally less expensive to build feeders in rural areas than in suburban or urban areas. Thus, while $150,000 is a good average cost, a mile of new feeder construction could cost as little as $55,000 in some situations and as much as $500,000 in others.

A typical distribution feeder (three-phase, 12.47 kV, 600 MCM/phase) would be rated at a thermal (maximum) capacity of about 15 MVA and a recommended economic (design) peak loading of about 8.5 MVA peak, depending on losses and other costs. At $150,000/mile, this capacity rating gives somewhere between $10 to $15 per kW-mile as the cost for basic distribution line. Underground construction of a three-phase primary feeder is more expensive, requiring buried ductwork and cable, and usually works out to a range of $30 to $50 per kW-mile.

Figure 2.8 Here, a service transformer, fed from a distribution primary-voltage lateral, feeds in turn ten homes through a secondary circuit operating at utilization voltage.

Lateral lines, short primary-voltage lines working off the main three-phase circuit, are often single- or two-phase and consequently have lower costs but lower capacities. Generally, they are about $5 to $15 per kW-mile overhead, with underground costs of between $5 to $15 per kW-mile (direct buried) to $30 to $100 per kW-mile (ducted).

Cost of other distribution equipment, including regulators, capacitor banks and their switches, sectionalizers, line switches, etc., varies greatly depending on the specifics of each application. In general, the cost of the distribution system will vary from between $10 and $30 per kW-mile.

Service Level Costs

The service or secondary system consists of the service transformers that convert primary voltage to utilization voltage, the secondary circuits that operate at utilization voltage, and the service drops that feed power directly to each consumer. Without exception these are very local facilities, meant to move power no more than a few hundred feet at the very most and deliver it to the consumer “ready to use.”

Many electric utilities develop cost estimates for this equipment on a per-consumer basis. A typical service configuration might involve a 50 MVA pole-mounted service transformer feeding ten homes, as shown in Figure 2.8. Costs for this equipment might include:

For a cost of about $330 per consumer, or about $66/kW of coincident load.

Maintenance and Operating Costs

Once put into service, T&D equipment must be maintained in sound, operating condition, hopefully in the manner intended and recommended by the manufacturer. This will require periodic inspection and service, and may require repair due to damage from storms or other contingencies. In addition, many utilities must pay taxes or fees for equipment (T&D facilities are like any other business property). Operating, maintenance, and taxes are a continuing annual expense.

It is very difficult to give any generalization of O&M&T costs, partly because they vary so greatly from one utility to another, but mostly because utilities account for and report them in very different ways. Frankly, the authors have never been able to gather a large number of comparable data sets from which to produce even a qualitative estimate of average O&M&T costs.⁸ With that caveat, a general rule of thumb: O&M&T costs for a power delivery system probably run between 1/8 and 1/30 of the capital cost, annually.

The Cost to Upgrade Exceeds the Cost to Build

One of the fundamental factors affecting design of T&D systems and management of an electric utility is that it costs more to upgrade equipment to a higher capacity than to build to that capacity in the original construction. For example, a 12.47 kV overhead, three-phase feeder with a 9 MW peak load capability (336 MCM phase conductor) might cost $240,000/mile to build ($26.66 per kW-mile). Building it with a 600 MCM conductor instead, for a capacity of 15 MVA, would cost in the neighborhood of $300,000 ($20/kW-mile).

⁸ For example, some utilities include part of O&M expenses in overhead costs, others do not. A few report repairs (including storm damage) as part of O&M, others accumulate major repair work separately. Others report parts of routine service (periodic rebuilding of breakers) as a type of capital cost because it extends equipment life or augments capacity. Others report all such work as O&M. Such differences are common among utilities.

However, upgrading an existing 336 MCM, 9 MW capacity line to 600 MCM and 15 MVA capacity could probably cost the utility at least $500,000/mile - over $83 per kW-mile for the additional capacity. It is more expensive because replacement entails removing the old conductor and installing a new conductor along with brackets, cross-arms, and other hardware required supporting the heavier new conductor. Another factor is that typically this work has to be done “hot” (i.e., with the feeder energized and feeding power to customers) which means the work must be undertaken with extreme care and following a number of safety-related procedure that require additional equipment and labor. By contrast the original construction is done cold – with the power turned off and no customers yet served by the circuit.

Thus, T&D planners have an incentive to look at their long-term needs carefully, and to "overbuild" against initial requirements if growth trends show future demand will be higher. The cost of doing so must be weighed against long-term savings, but often T&D facilities are built with considerable margin (50%) above existing load to allow for future load growth.

The very high cost per kW for upgrading a T&D system in place creates one of the best-perceived opportunities for DSM and DG reduction. Note that the capital cost/kW for the upgrade capacity in the example above ($33/kW) is nearly three times the cost of similar new capacity. Thus, planners often look at areas of the system where slow, continuing load growth has increased load to the point that local delivery facilities are considerably taxed, as areas where DSM and DG can deliver significant savings.

In some cases, distributed resources can reduce or defer significantly the need for T&D upgrades of the type described above. However, this does not assure significant savings for the situation is more complicated than an analysis of capital costs to upgrade may indicate. If the existing system (e.g., the 9 MW feeder) needs to be upgraded, then it is without a doubt highly loaded, which means its losses may be high, even off-peak. The upgrade to a 600 MCM conductor will cut losses 8,760 hours per year. Financial losses may drop by a significant amount, enough in many cases to justify the cost of the upgrade alone. The higher the annual load factor in an area, the more likely this is to occur, but it is often the case even when load factor is only 40%. However, DSM and in some cases DG also lowers losses, making the comparison quite involved, as will be discussed later in this book.

Electrical Losses Costs

Movement of power through any electrical device, be it a conductor, transformer, regulator or whatever, incurs a certain amount of electrical loss due to the impedance (resistance to the flow of electricity) of the device. These losses are a result of inviolable laws of nature. They can be measured, assessed, and minimized through proper engineering, but never eliminated completely.

Total T&D Costs

What is the total cost to deliver electric power? Of course this varies from system to system as well as from one part of a system to another - some consumers are easier to reach with electric service than others (Figure 2.9). Table

2.2 shows the cost of providing service to a “typical” residential consumer. Generally, a utility amortizes the capital cost of 30 or more years and tries to minimize the total present worth lifetime cost. More detail in how costs are accounted and minimized in planning and operations can be found in Brown, 2009.

Large-Trunk vs. Multi-Branch Feeder Layout

Figure 2.13 illustrates the basic concept behind two different ways to approach the layout of a radial distribution system. Each has advantages and disadvantages with respect to the other in certain situations, and neither is superior to the other in terms of reliability, cost, ease of protection, and service quality. Either can be engineered to work in nearly any situation. Most planning utilities have an institutionalized preference for one or the other. Beyond showing that there are significantly different ways to lay out a distribution system, this brings to light an important point about distribution design: major differences in standards exist among electric utilities, as a result of which comparison of statistics or practice from one to the other is often not valid. Feeder layout types and practices are discussed in much greater detail in the Power Distribution Planning Reference Book.

Service Areas

As mentioned earlier, in most power systems, each substation is usually the sole provider of electrical service to the region around it - its service area. Similarly, feeders and distribution networks also have distinct service areas. Usually, the service area for a substation, feeder, or other unit of equipment is the immediate area surrounding it, and usually these service areas are contiguous (i.e. not broken into several parts) and exclusive - no other similar distribution unit serves any of the load in an area. As an example, Figure 2.14 shows a map of substation service areas for a rectangular portion of a power system. Each distribution substation exclusively serves all consumers in the area containing it.

Cumulatively, the simultaneous peak demand of all customers in its service area defines the maximum power the substation must serve. Within a power system, each individual part, such as a substation or service transformer, will see its peak load at whatever time and in whatever season the consumers in its service area generate their cumulative peak demand. One result of this is that the peak loads for different substations often occur at different seasons of the year or hours of the day. But whenever the peak occurs, it defines the maximum power the unit is required to deliver. Peak demand is one of the most important criteria in designing and planning distribution systems. Usually it defines the required equipment capacity.

Dynamic Service Area Planning

By making switching changes in the distribution system, it is possible to expand or shrink a substation or feeder’s service area significantly, increasing or decreasing its net load. This is an important element of T&D planning, as shown in Figure 2.15, which illustrates a very typical T&D expansion situation. Two neighboring substations, A and B, each have a peak load near the upper limit of their reliable load-handling range. Load is growing slowly throughout the system, so that in each substation annual peak load is increasing at about 1 MW per year. Under present conditions, both will need to be upgraded soon. Approved transformer types, required to add capacity to each, are available only in 25 MVA increments, costing $500,000 each. Both substations do not need to be reinforced. A new 25 MVA transformer and associated equipment are added to substation A, increasing its ability to handle a peak load by about 20 MVA. Ten MW of substation B’s service area is then transferred to substation A. The result is that each substation has 10 MW of margin for continued load growth - further additions are not needed for 10 years.

Figure 2.15 Load in both substations is growing at about 1 MW per year. Each substation has sufficient capacity to handle present load within contingency criteria (a 25% margin above peak) but nothing more. By transferring load as shown above, only one substation has to be reinforced with an additional (25 MVA) capacity, yet both end up with sufficient margin for another ten years’ growth. Service area shifts keep expansion costs down in spite of the fact that equipment like transformers are available only in large, discrete sizes.

This type of planned variation in service areas is a major tool used to keep T&D expansion costs low, a key element in building a reliable, economical schedule of expansion. Optimization of this particular aspect of planning can be a challenge, not because of any inherent difficulty in analysis, but simply because there are so many parts of the system and constraints to track at one time. This is one reason for the high degree of computerization in distribution planning at many utilities. Balancing the myriad requirements of many substations and their design and operating constraints is an ideal problem for numerical optimization techniques.

The Systems Approach

One complication in determining the most economical equipment for a power system is that its various levels - transmission, substation, and distribution - are interconnected, with the distribution in turn, connected to the consumers and hence a function of the local load density. The best size and equipment type at each level of the system is a function of the types of equipment selected for the other levels of the system and the load density. In general, the equipment is so interconnected that it is impossible to evaluate any one aspect of design without taking all others into account.

Consider the question of substation spacing - determining how far apart substations should be, on average for best utilization and economy. Within any service territory, if substations are located farther apart, there will be fewer of them, saving the utility the cost of buying and preparing some substation sites, as well as reducing the cost of building a large number of substations.

Thus, overall substation cost is a function of spacing, but how it varies depends on land and equipment costs, which must be balanced carefully. With fewer substations however, each substation must serve a larger area of the system. Hence, each substation will have a larger load and thus require a larger capacity, meaning it must have more or larger transformers.

The larger substations will also require a larger amount of power to be brought to each one, which generally calls for a higher sub-transmission voltage. Yet there will be fewer sub-transmission lines required because there are fewer substations to which power must be delivered. All three aspects of layout are related - greater substation spacing calls for larger substations with bigger transformers, and a higher transmission voltage, but fewer lines are needed - and all three create better economies of scale as spacing is increased. Thus, transmission costs generally drop as substation spacing is increased.

Nevertheless, there is a limit to this economy. The distribution feeder system is required to distribute each substation's power through its service area, moving power out to the boundary between each substation’s service area and that of its neighbors. Moving substations farther apart means that the distribution system must move power, on average, a greater distance. Distributing power over these longer distances requires longer and more heavily loaded feeders. This situation increases voltage drop and can produce higher losses, all of which can increase cost considerably. Employing a higher distribution voltage (such as 23.9 kV instead of 13.8 kV) improves performance and economy, but it costs more to distribute power from a few larger substations farther apart, than to distribute it from many smaller substations close together. Feeder costs go up rapidly as substation spacing is increased.

The major point of this section is that all four of the above aspects of system design are interconnected - 1) substation spacing in the system, 2) size and number of substations, 3) transmission voltage and design and, 4) distribution feeder voltage and design. One of these factors cannot be optimized without close evaluation of its interrelationship with the other three. Therefore, determining the most cost-effective design guideline involves evaluating the transmission-substation-feeder system design as a whole against the load pattern, and selecting the best combination of transmission voltage, substation transformer sizes, substation spacing, and feeder system voltage and layout.

Figure 2.16 Overall cost of a T&D system depends on the balanced design of the sub-transmission, substation, and feeder level, as described in the text. Cost can vary by significant margins depending on how well performance and economy at various levels of the system are coordinated.

This economic equipment sizing and layout determination is based on achieving a balance between two conflicting cost relationships:

1. Higher voltage equipment is nearly always more economical on a per-MW basis.

2. Higher voltage equipment is available only in large sizes (lots of MW).

In cases where the local area demands are modest, higher voltage equipment may be more expensive simply because the minimum size is far above what is required - the utility has to buy more than it needs. How these two cost relationships play against one another depends on the load and the distances over which power must be delivered. Other factors to be considered are those unique to each power system, such as the voltages at which power is delivered from the regional power pool, and whether the system is underground or overhead.

Figure 2.16 illustrates the difference that careful coordination of system design between levels of the power system can have in lowering overall cost. Shown are the overall costs from various combinations of a T&D system layout for a large metropolitan utility in the eastern United States. Each line connects a set of cost computations for a system built with the same transmission and distribution voltages (e.g., 161 kV transmission and 13.8 kV distribution) but varying in substation sizes (and hence, implicitly, their spacing).

In all cases, the utility had determined it would build each substation with two equally sized transformers (for reliability), with none over 75 MVA (larger transformers are too difficult to move along normal roads and streets, even on special trailers). Either 161 kV or 69 kV could be used as sub-transmission, either

23.9 kV or 13.8 kV could be used as distribution voltage. Any size transformer, from 15 MVA to 75 MVA could be used, meaning the substation could vary from 30 MVA to 150 MVA in size. (Peak load of such substations can normally be up to 75% of capacity, for a peak load of from 23 to 100 MW.)Substation spacing itself is implicit and not shown. Given the requirement to cover the system, determining transmission voltage, distribution, and substation size defines the system design guidelines entirely.

Overall, the ultimate and lowest cost T&D system guidelines are to build 120 MVA substations (two 60 MVA transformers) fed by 161 kV sub-transmission and distributing power at 23.9 kV. This has a levelized cost (as computed for this utility) of about $179/kW. In this particular case, a high distribution voltage is perhaps the most important key to good economy - if 13.8 kV is used instead of

23.9 kV as the primary voltage, minimum achievable cost rises to $193/kW.

The very worst design choices plotted in Figure 2.16, from an economic standpoint, would be to build 25 MVA substations fed by 161 kV sub-transmission and feeding power to 23.9 kV feeders ($292/kW). This would require many small substations, each below the effective size of both the transmission and distribution voltages, and lead to high costs. Overall, 161 kV and 23.9 kV are the correct choices for economy, but only if used in conjunction with a few, large substations. If substations are to be 25 MVA, then 69 kV and

13.8 kV do a much more economical job ($228/kW), but still don't achieve anything like the optimum value. The point: Achieving economy in power delivery involves coordinating the interactions, performance, and economies of the multiple system levels. Chapters 11 and 12 discuss the issues of and techniques for such coordinated multi-level planning.

A Complicated System

In conclusion, a power T&D system provides the delivery of an electric utility’s product. It must deliver that product to every consumer’s site, with high reliability and in ready-to-use form. While composed of equipment that is individually straightforward, most T&D systems are quite complex due to the interactions of thousands, even millions, of interconnected elements. Achieving economy and reliability means carefully balancing a myriad of mutual interactions with conflicting cost tradeoffs.