Technical Aspects of Grid Interconnection
2.1.1. The Evolution of Interconnected Systems
Electricity grid interconnections have played a key role in the history of electric power systems. Most
national and regional power systems that exist today began many decades ago as isolated systems, often as
a single generator in a large city. As power systems expanded out from their urban cores, interconnections
among neighboring systems became increasingly common . Groups of utilities began to form power
pools, allowing them to trade electricity and share capacity reserves. The first power pool in the United
States was formed in the Connecticut Valley in 1925 . As transmission technologies improved, long distance
interconnections developed, sometimes crossing national borders. The first international interconnections
in Europe came in 1906, when Switzerland built transmission links to France and Italy.
One of the great engineering achievements of the last century has been the evolution of large synchronous
alternating current (AC) power grids, in which all the interconnected systems maintain the
same precise electrical frequency. Today, the North American power system is composed of four giant
synchronous systems, namely the Eastern, Western, Texas, and Quebec interconnections. The Eastern
interconnection by itself has been called the largest machine in the world, consisting of thousands of
generators, millions of kilometers of transmission and distribution lines, and more than a billion different
electrical loads. Despite this complexity, the network operates in synchronism as a single system. So
does the Western European interconnection, which reaches from the UK and Scandinavia to Italy and
Greece, embracing along the way much of Eastern Europe (for example, Poland, Hungary, Slovakia,
and the Czech Republic). Synchronous interconnections among countries are expanding in Central and
South America, North and Sub-Saharan Africa, and the Middle East10.
At the same time that synchronous AC networks have reached the continental scale, the use of
high voltage direct current (HVDC) interconnections is also rapidly expanding as a result of technical
progress over the last two decades. HVDC permits the asynchronous interconnection of networks that
operate at different frequencies, or are otherwise incompatible, allowing them to exchange power without
requiring the tight coordination of a synchronous network. HVDC has other advantages as well,
especially for transmitting large amounts of power over very long distances. Fundamentals of both AC
and DC interconnections are discussed below in Sections 2.2, 2.3, and 2.4 of this Chapter.
2.1.2. General potential benefits of grid interconnections
There are number of technical rationales for grid interconnections, many of which have economic components
as well (as described in Chapter 3 of this Report). Technical rationales for grid interconnection include:
• Improving reliability and pooling reserves: The amount of reserve capacity that must be built by
individual networks to ensure reliable operation when supplies are short can be reduced by sharing
reserves within an interconnected network.
• Reduced investment in generating capacity: Individual systems can reduce their generating capacity
requirement, or postpone the need to add new capacity, if they are able to share the generating
resources of an interconnected system.
• Improving load factor and increasing load diversity: Systems operate most economically when the
level of power demand is steady over time, as opposed to having high peaks. Poor load factors (the
ratio of average to peak power demand) mean that utilities must construct generation capacity to
meet peak requirements, but that this capacity sits idle much of the time. Systems can improve poor
load factors by interconnecting to other systems with different types of loads, or loads with different
daily or seasonal patterns that complement their own.
• Economies of scale in new construction: Unit costs of new generation and transmission capacity
generally decline with increasing scale, up to a point. Sharing resources in an interconnected system
can allow the construction of larger facilities with lower unit costs.
• Diversity of generation mix and supply security: Interconnections between systems that use different
technologies and/or fuels to generate electricity provide greater security in the event that one kind
of generation becomes limited (e.g., hydroelectricity in a year with little rainfall). Historically, this
complementarity has been a strong incentive for interconnection between hydro-dominated systems
and thermal-dominated systems. A larger and more diverse generation mix also implies more diversity
in the types of forced outages that occur, improving reliability.
• Economic exchange: Interconnection allows the dispatch of the least costly generating units within
the interconnected area, providing an overall cost savings that can be divided among the component
systems. Alternatively, it allows inexpensive power from one system to be sold to systems with more
• Environmental dispatch and new plant siting: Interconnections can allow generating units with
lower environmental impacts to be used more, and units with higher impacts to be used less. In areas
where environmental and land use constraints limit the siting of power plants, interconnections can
allow new plant construction in less sensitive areas.
• Coordination of maintenance schedules: Interconnections permit planned outages of generating
and transmission facilities for maintenance to be coordinated so that overall cost and reliability for
the interconnected network is optimized.
Some costs and benefits of interconnections are difficult to quantify, but as a rough figure of merit it
has been estimated that interconnections in North America have resulted in an overall annual cost savings
of $20 billion in the 1990s, and that the Western European interconnection has resulted in reduced
capacity requirements of 7-10 percent.
2.1.1. Technical complexities and risks of grid interconnections
The fact that interconnections between power systems are increasingly common does not imply that they
are as simple as connecting a few wires. Interconnections obviously entail the expense of constructing
and operating transmission lines and substations, or in the case of HVDC, converter stations. Interconnections
also entail other costs, technical complexities, and risks. For AC interconnections especially, a
power system interconnection is a kind of marriage, because two systems become one in an important
way when they operate in synchronism. To do this requires a high degree of technical compatibility and
operational coordination, which grows in cost and complexity with the scale and inherent differences of
the systems involved. To give just one example, when systems are interconnected, even if they are otherwise
fully compatible, fault currents (the current that flows during a short circuit) generally increase,
requiring the installation of higher capacity circuit breakers to maintain safety and reliability. To properly
specify these and many other technical changes required by interconnection requires extensive planning
studies, computer modeling, and exchange of data between the interconnected systems.
The difficulties of joint planning and operation of interconnected systems vary widely. As with marriages,
from the institutional and administrative standpoint, coupled systems may become a single entity,
or they may keep entirely separate accounts. Within the North American interconnections, for example,
there are hundreds of electric utility companies that are entirely separate commercial entities. Customers
receive power from, and pay bills to, the utility that serves their area, for example Consolidated Edison.
They may do so without even knowing of the existence of the Eastern interconnection. Yet all the utilities
in the Eastern interconnection are in a technical marriage that dictates or constrains key aspects of their
technology choices and operating procedures.
Within countries, there are typically common technical standards for all utilities, which reduces
the complexity of interconnecting separate systems. In different countries, on the other hand, power
systems may have evolved quite separately, with very different standards and technologies, which adds
an extra layer of technical complexity to interconnections. Institutional and administrative features of
power systems in different countries are also likely to differ in many ways, and these differences invariably
affect the technical and operational dimensions of an interconnection. Issues ranging from power trading
agreements to reliability standards, while expressed in technical terms, often must be resolved within the
realm of policy and political economy. As one expert on international interconnections has remarked,
“many technical, organizational, commercial and political problems have had to be solved to get large
networks linked by international interconnections to operate”11.
The greatest benefits of interconnection are usually derived from synchronous AC operation, but
this can also entail greater reliability risks. In any synchronous network, disturbances in one location are
quickly felt in other locations. After interconnecting, a system that used to be isolated from disturbances
in a neighboring system is now vulnerable to those disturbances. As major blackouts in North America
and Europe in 2003 demonstrated, large-scale disturbances can propagate through interconnections and
result in cascading outages, bringing down systems that had previously been functioning normally. In
addition, long-distance interconnections with long transmission lines have potentially greater stability
problems than is the case for shorter lines. Finally, many systems that have undergone electricity liberalization
in recent years have experienced large increases in transmission capacity utilization, reducing
reserve margins. Minimizing the likelihood that an interconnection will lead to such problems as voltage
collapse, dynamic and transient instability, or cascading outages due to propagated disturbances requires
careful planning and well-coordinated operation.
2.2. Technical parameters of interconnection
2.2.1. Basic Electrical Parameters
This section describes the basic electrical parameters and units of measurement used in electric power
systems. It is meant to provide the non-technical reader with the concepts needed for a general understanding
of the technical issues discussed in subsequent sections.
AC & DC
Electric power comes in two forms: alternating current (AC) and direct current (DC). These forms are
characterized by the behavior of their waveforms: AC alternates between positive and negative polarity
with respect to ground, while DC does not. In power systems, AC is generally a sine wave, while DC is a
constant value. Early electricity systems, such as Thomas Edison’s Pearl Street Station in New York City,
which provided the world’s first public electric service in 1882, were DC. However, by the beginning
of the 20th century AC systems had become standard worldwide. The main reason for the adoption of
AC was that it is relatively simple to change AC voltage levels by using transformers, while it is difficult
to change DC voltages. The development of solid-state power electronics in recent years has allowed an
increased use of DC in the form of HVDC interconnections, but otherwise power systems remain AC.
Frequency is the rate at which an alternating current changes from positive to negative polarity, measured
in cycles per second, or hertz (Hz). There are currently two widespread world standards for power system
frequency: 50 Hz in most of Europe and Asia, and 60 Hz in North America and in other places strongly
influenced by the U.S. power industry, such as South Korea. The choice of 50 and 60 Hz systems in
different locations is a consequence of historical legacies rather than the inherent technical superiority of
one or the other. However, the range of possible frequencies for power systems is constrained by practical
concerns. For example, a century ago many electric railroads operated at a frequency of 25 Hz, but 25
Hz was never adopted for general use in power systems because frequencies at that level cause electric
lights to flicker. At the other end of the scale, frequencies well above 60 Hz result in higher impedances,
leading to unacceptably high transmission and distribution losses.
Voltage is the difference in electric potential between two points in an electric circuit. A difference in
potential causes electric charges to flow from one place to another, just as a difference in heights causes
water to flow from one level to another. Voltage is measured in volts (V), and sometimes in thousands
of volts or kilovolts (kV).
In power systems, two important measures are the maximum voltage and average voltage at any particular
point. Maximum voltage is important because insulation and safety equipment must be designed
to protect against the highest voltage encountered. Average voltage is important because the amount of
energy supplied to an end user or lost in transmission lines is a function of the average voltage and current.
For DC systems, maximum and average voltages are the same, because DC voltage doesn’t oscillate.
For example, the output of a 120 V DC power supply is a continuous 120 V relative to ground, and this is
both the maximum and average voltage.
For AC systems, different measures are required. In a 120 V AC system, the voltage actually oscillates in
a sine wave between + 170 V and – 170 V relative to ground. The maximum voltage, also called amplitude or
peak voltage, is thus 170 V. The simple arithmetic average of this waveform is actually 0 V, since the positive
and negative voltages cancel each other out. Hence, another type of average is used, called root-mean-square
(RMS). RMS is obtained by squaring the values of the voltage over one complete sine-wave cycle, determining
its average value, and then taking the square root of that average. The result (true for any sine wave) is that VRMS
= VPEAK / √2 = 0.707 VPEAK. For a household system with a VPEAK = 170 V, VRMS = 0.707 (170 V) = 120 V. Thus
the common designation of a household electric outlet as “120 V AC” refers to the RMS value of the voltage.
The voltages of power system components, such as transformers and transmission lines, are also generally given
in RMS terms.
Current is the flow rate of electric charge. In an electric circuit, charge flows from a point of higher voltage to a
point of lower voltage through a conductor, just as water flows from a higher spot to a lower one through a pipe.
Current is measured in amperes (A) or kilo-amperes (kA), where one ampere is a certain number of charges (to
be precise 6.25 x 1018 charges, called one coulomb) flowing per second. As is the case for voltage, AC currents
are generally described in terms of their RMS values.
Resistance and Conductance
Conductance describes the ability of an object, such as an electric wire, to allow electric currents to flow.
The reciprocal of conductance is resistance, which describes how much the object resists the flow of current.
Resistance is measured in ohms (Ω). The resistance of wire is a product of its resistivity (an inherent
property of the material from which it is made, such as copper or aluminum, for a given temperature)
and the dimensions of the wire. For a given material, the longer the wire is, the greater the resistance,
and the larger in diameter the wire is, the smaller the resistance. In the analogy of water flowing from a
higher to a lower spot through a pipe, resistance is analogous to the friction of the pipe. A narrow pipe
has a higher resistance; a wide pipe has a lower resistance.
Ohm’s Law describes the relationship between voltage (V), current (I), and resistance (R) across any element
of a DC electric circuit: V = I∗R. Thus, for a fixed value of resistance – say for an HVDC transmission
line of a certain length and diameter – if the voltage is made larger, the current will decrease, and
vice versa. For example, if the resistance of a line is 25 Ω, and the current through the line is 1 kA, then
the voltage drop across the line is V = 1 kA * 25 Ω = 25 kV. If the voltage on the sending side was 500
kV, then the voltage on the receiving side must be 25 kV less, or 475 kV.
Power and Energy
Power is the rate of energy flow, measured in watts (W), and sometimes in thousands of watts or kilowatts
(kW), or in millions of watts or megawatts (MW). For a DC circuit, the power passing through any
element of the circuit (e.g. a transmission line, a generator, an electrical appliance) is the product of the voltage
across it and the current passing through it: P = I∗V.
The energy delivered by a power system is measured in kilowatt-hours (kWh), and sometimes megawatthours
(MWh). In general, energy is equal to power times time. For example, a light bulb that draws 100 W of
power and is in use for 10 hours consumes a total amount of energy, E = 0.1 kW * 10 h = 1 kWh. Note that
power and energy are quite different concepts. If an electric oven draws 1 kW of power and is in use for an hour,
E = 1 kW * 1 h = 1 kWh. In these two examples, the power levels are different but the energy consumed is the
same, the difference being the length of time that each device is operated.
Note that the basic unit of energy is the joule (J), while the basic unit of power is the watt, where 1 W = 1
J/s. Thus 1 kWh = 1 kW * 1 h = 1000 J/s * 3600 s = 3.6 million J.
When current flows against a resistance, some of its energy is lost in the form of heating. For a DC circuit, the
resistive losses can be calculated using Ohm’s Law: PLOSS = I∗V = I(I/R) = I2R. To continue with the example
under “Ohm’s Law” above, consider a 500 kV HVDC transmission line with 25 Ω of resistance, with 1 kA of
current passing through it, and which has a voltage on the sending end of 500 kV, and a voltage on the receiving
end of 475 kV. The total power being transmitted at the sending end of the transmission line is P = 500 kV ∗
1 kA = 500 MW. Out of this 500 MW, the amount being lost to heating is PLOSS = (1 kA)2 ∗ 25 Ω = 25 MW.
This constitutes 25 MW/500 MW = 5 percent of the power being transmitted.
Very high voltages are used in transmission in order to reduce resistive losses to a tolerable level. In
the example above, if the same amount of power were being transmitted (500 MW) but the sending voltage
were 125 kV instead of 500 kV, the current through the line must be I = P/V = 500 MW/125 kV = 4
kA; the current is four times higher to yield the same amount of power, because the voltage is four times
less. The power lost in the transmission line is then PLOSS = (4 kA)2 ∗ 25 Ω = 400 MW = 80 percent of
the power being transmitted. In general, line losses are inversely proportional to the square of the sending
voltage; this is true for AC lines as well as DC. For this reason, historically power systems have sought
to increase their transmission voltages as distances and amounts of power transmitted have grown. The
highest common AC transmission voltages, sometimes referred to as extra high voltage (EHV), are 380
kV in Europe and 765 kV in the US. Voltages as high as 1200 kV have been used in Russia for some
long-distance lines across Siberia. Above 1000 kV, however, the practical difficulty and expense of equipment
and insulation that can withstand such high voltages becomes prohibitive.
Impedance, Reactance, Inductance, Capacitance
AC circuits involve not only resistance but other physical phenomena that impede the flow of current. These
are inductance and capacitance, referred to collectively as reactance. When AC currents pass through a reac
tance (e.g. in transmission and distribution lines, in transformers, or in end-use equipment such as electric
motors) some of the energy is temporarily stored in electro-magnetic fields. This has three important implications.
(1) Even though energy is not “lost” to the environment as in the case of resistive heating, it must still
be supplied to the reactive elements. This is known as reactive power. (2) Voltage decreases when current flows
across a reactance, just as it does across a resistance. For AC circuits, Ohm’s Law must be modified: V = I∗Z,
where Z is the sum of resistance and reactance, called impedance, and is measured in ohms. (3) V, I, and Z are
all complex numbers, meaning that they express not only magnitudes in volts, amps, and ohms, but also phase
angles. Voltage and current waveforms both oscillate at same frequency - either 50 Hz or 60 Hz depending on
the system – but they can differ in terms of the angular location within a cycle at which the maximum voltage
or current occurs. This difference in angular location is referred to as phase difference, often symbolized by φ
(phi) or θ (theta) and measured in degrees (or radians). Passing through an inductance causes an AC current
waveform to fall behind, or lag, the voltage waveform. Passing through a capacitance causes AC current to
move ahead of, or lead, the voltage. Equivalent amounts of capacitance and reactance cancel each other out.
Complex Power: Real, Reactive, Apparent
For AC systems, there are three kinds of power: real, reactive, and apparent. Real power (sometimes
called active power) is what is consumed by resistances, and is measured in W (or kW, or MW). Reactive
power is consumed by reactances, and is measured in volt-amperes reactive, or VAR (sometimes kVAR,
or MVAR). Apparent power is the complex sum of real and reactive power, and is measured in voltamperes,
or VA (or kVA or MVA). S = √(P2 + Q2), where S is apparent power, P is real power, and Q is
reactive power. Apparent power is what must be supplied by the generators in a power system to meet the
system’s electrical load, whereas end-use is generally measured in terms of real power only. Utilities always
seek to minimize reactive power consumption, among other reasons because it is difficult to measure and
be compensated for reactive power by customers.
Loads and Power Factors
An electrical load is the power drawn by an end-use device or customer connected to the power system.
(Sometimes, “load” is used to refer to the end-use devices or customers themselves, but among engineers it
usually refers to the power demand.) Loads can be resistive or reactive, and are often a combination of both. The
extent to which a load is resistive is measured by its power factor, (p.f.), which is equal to the cosine of the phase difference
between the current and voltage through the load: p.f. = cos φ. When the power factor is at its maximum
value of one, the load is purely resistive. On the other hand, the smaller the power factor, the greater the phase
difference and the greater the reactive power component of the load. Inductive loads, such as electric motors, have
a lagging power factor (see 2.1.9), and are said to consume reactive power. Capacitive loads have a leading power
factor and are said to be sources of reactive power.
Given the voltages and currents through a circuit element, apparent, real, and reactive power can be
calculated respectively as follows:
S = IRMS * VRMS
P = S * p.f. = IRMS * VRMS * cos φ
Q = IRMS * VRMS * sin φ
Reactive loads can have a large effect on line losses, because the current flowing through a line, and
the associated heating, is a function of the apparent power S rather than the real power P. For example,
consider a load of 150 kW with a lagging power factor of 0.75, which is supplied by a 10 kV distribution
line with a resistance of 10 Ω. The apparent power drawn by the load is S = P/p.f. = 150 kW/0.75 =
200 kVA. The current to the load is then I = 200 kVA/10 kV = 20 A. The line loss is PLOSS = I2 * R = (20
A)2 * 10 Ω = 4 kW. If there were no reactive power consumption by the load, the power factor would be
equal to one. In that case, S = P = 150 kW. Then I = 150 kW/10 kV = 15 A, and PLOSS = (15 A)2 * 10 Ω
= 2.25 kW. Thus the reactive load in this example increased the line losses from 2.25 kW to 4 kW, an
increase of 78 percent.
House current is generally single-phase AC power, but the rest of the power system from generation to
secondary distribution employs 3-phase AC. This means that transmission lines have three separate conductors,
each carrying one-third of the power. The waveforms of the voltage in each phase are separated
by 120°. There are two major reasons that 3-phase power became dominant. (1) As long as the electrical
loads on each phase are kept roughly balanced, only three wires are required to transmit power. Normally,
any electric circuit requires both an “outbound” and “return” wire to make a complete circuit. Balanced
3-phase circuits provide their own return, and thus only three, rather than six, wires are required to
transmit the same amount of power as three comparable single-phase systems. (2) Since the invention
of polyphase induction motors by Nikola Tesla in the 1890s, 3-phase motors have been the workhorse
of industry. More than one phase is required to balance torque, which increases the effectiveness and
lifetime of both motors and generators.
Voltage and Power in Three-Phase Systems
The voltage in 3-phase systems can be specified in two different ways. One is phase to ground, which as
it sounds is the voltage between any one of the three phases and ground. The other is phase to phase,
which is the voltage between any two of the three phases. Power lines are conventionally described by
their phase to phase voltage, also called the line voltage. Phase to phase voltage is greater than phase to
ground voltage by a factor of the square root of three. Thus, a 500 kV line has a phase to phase voltage
of 500 kV, and a phase to ground voltage of 500 kV/√3 = 289 kV. In both cases, the voltage referred to
is the RMS value.
The amount of power transmitted in a three-phase system is three times the power in each line. Thus
S = 3 (I * VLINE/√3) = √3 I * VLINE, where VLINE is the phase to phase voltage. For example, the apparent
power transmitted by a 500 kV circuit with a current of 1 kA is S = √3 * 500 kV * 1 kA = 866 MVA.
The real and reactive components can be calculated easily if the load power factor or phase difference is
known (see 2.1.10). In this example, if φ = 25°, the real power P = S cos 25° = 866 MVA * 0.906 = 785
MW, and the reactive power Q = S sin 25° = 866 MVA * 0.422 = 366 MVAR.
2.2.2. Basic Design Features
The basic design features of an interconnection include the following elements:
• whether it is AC or DC
• if DC, whether it is single-pole or double-pole (+/-)
• transmission capacity (in MVA)
• transmission voltage (in kV)
• system components and overall design
• operating agreement
These features are dictated by the answers to the following questions:
• Will the interconnected systems operate synchronously or asynchronously? To operate synchronously,
at a minimum the systems must have the same nominal frequency (50 Hz or 60 Hz). Even
if frequencies are the same, technical and operational differences can make synchronous operation
too difficult or expensive to pursue. Many synchronous networks with the same nominal frequency,
including the four North American interconnections, have only asynchronous DC connections
• What are the magnitudes and directions of the anticipated power flows? The basic rationales for
the interconnection must be expressed quantitatively, using models that forecast the power flows
through the interconnection among constituent systems. The forecasts must be conducted on different
time scales: diurnal, seasonal, annual, and multi-year projections.
• What physical distance and terrain will the interconnection span? The peak power flows and the
physical length of the interconnection will influence the choice of AC or DC, the size of conductors,
and requirements for other system components, such as series capacitors or phase-shifting
transformers. Terrain, geology, and land use considerations (such as urban areas, environmentally
sensitive areas) will determine whether overhead lines or underground cables are used, the layout and
design of substations or converter stations, grounding and lightning protection schemes, and the
most suitable kinds of support structures. Undersea transmission requires the use of special cables
that are quite different from terrestrial cables and overhead lines. Terrain and land use also dictate
construction and maintenance methods.
• What are the key technical and operating differences among the systems to be interconnected?
These include differences in the hardware, control systems, and procedures used for frequency regulation,
voltage regulation, and fault protection.
2.2.1. Interconnection Elements
A listing of the basic elements of an interconnection is provided below.
The ultimate objective of an interconnection, like the power systems it is part of, is to provide power
to customers economically, safely, reliably, efficiently, and with minimal environmental impact. Each of
these aspects has one or more quantitative measure, such as price per kilowatt-hour, number and lethality
of accidents, frequency and duration of service interruptions, generating plant heat rate, transmission and distribution losses, and emissions factors. Interconnections are designed, and their individual
components selected, with all of these objectives in mind, though they may be optimized differently in
Transmission lines come in two basic varieties: overhead lines and underground (or undersea) cables.
Overhead lines are more common and generally less expensive than cables. The main design consideration
for overhead lines is the choice of conductor type and size, which must balance the need to
minimize impedance (and the associated losses), minimize cost, and minimize the weight that must be
carried by support structures. Although copper is a better conductor, it has been overtaken in recent years
by aluminum, which is lighter, cheaper, and in abundant supply. The most common variety of overhead
conductor for high-capacity, long-distance transmission is stranded aluminum wire reinforced with steel
(known as ACSR, for “aluminum conductor steel reinforced”). Other design considerations for overhead
lines are the type of support structures (such as transmission towers and insulators) used, and the configuration
of conductors on the support structures, which affects the reactance of the conductors and the
strength of electromagnetic fields (EMFs) around the lines.
Underground cables are used where overhead conductors are inappropriate due to environmental
or land use considerations, such as in high-density urban areas or ecologically sensitive areas. Cables are
insulated and are typically routed through underground conduits, and often require cooling systems to
dissipate heat. Cables may use copper instead of aluminum, balancing the greater cost of copper against
its superior conductivity and lower resistive heating. Undersea cables are usually made of copper, and
may be surrounded by oil or an oil-soaked medium, then encased in insulating material to protect from
corrosion. Undersea cables often have a coaxial structure, which has an inherently high capacitive reactance;
therefore undersea cables are usually DC, which is not affected by reactance. Conductor cross-sections
are typically measured in square centimeters (cm2) in the metric system, or thousands of circular
mils (kcmil) in the American system12. The capacity of a conductor to carry current without exceeding
thermal limits is called its ampacity, measured in kA for large conductors.
There are many possible types of support structures for overhead transmission lines. In developed countries,
transmission lines are supported on structures made out of steel lattice, tubular steel, wood, and concrete.
Of these, steel lattice has the highest strength to weight ratio, and is the easiest to assemble in areas that are
difficult to access13. Where aesthetics are an important factor, however, other materials are often used. The
main function of support structures is to keep the conductors from contacting trees or other objects, including
people and animals; thus the structures must be tall enough to do so even when the conductors sag
due to high temperatures caused by resistive heating. All things being equal, taller structures also minimize
ground-level EMFs. Because overhead transmission lines are not insulated, they are typically suspended
from towers on strings of ceramic insulators, which are designed to prevent flashover, or the leakage of
current from the conductors to the tower, which would present a lethal prospect to anyone touching the
tower. AC transmission towers are usually designed to carry three conductors: the three phases of AC power
systems. Towers that hold these in an equilateral triangle shape (called a “delta”) keep the mutual reactances
of the three phases balanced; non-delta configurations often require that conductors be transposed, or switch
places, at regular intervals along the transmission path. Some towers carry more than one circuit, with
three phases per circuit; for example, a double-circuit tower will have six conductors. (The conductor for
each phase may also be subdivided into “bundles” of two or more conductors, which are physically close
together.) DC transmission towers carry two conductors per circuit. Figure 2-1 on the following page shows
various options for transmission tower design.
Transformers and Substations
Transformers are used to change voltage levels in AC circuits, allowing transmission at high voltages to
minimize resistive losses, and low voltages at the customer end for safety. This ability, following the development
of transformers by William Stanley in 1885, led to the rapid adoption of AC systems over DC
systems. The essential element of a transformer consists of two coils of wire wrapped around an iron core.
An alternating current in one coil produces a changing electromagnetic field that induces a current in the
other. The voltages on either side are in the same ratio as the number of turns on each coil. For example,
a transformer with a 10:1 “turns ratio” that is connected to a 15 kV supply on its primary side, will have
a voltage of 150 kV on its secondary side. Transformers step up the voltage from generator to transmission
system, and other transformers step it down, often in several stages, from transmission to sub-transmission
to primary distribution to secondary distribution, and finally to the end-user voltage, such as 120 V. At the
distribution level, transformers often have taps that can be used to change the turns ratio; this allows operators
to maintain customer voltage levels when system voltages change. Modern transformers are extremely
efficient, typically greater than 99%, but even small losses can produce a great deal of heat, which must be
dissipated to prevent damage to the equipment. Large transformers are cooled by circulating oil, which also
functions as an electrical insulator.
Large transformers are housed in substations, where sections of a transmission and distribution system
operating at different voltages are joined. Larger substations have a manned control room, while smaller substations
often operate automatically. In addition to transformers, important substation equipment includes switchgear,
circuit breakers and other protective equipment (see next section), and capacitor banks used to provide
reactive power support.
Protection systems are an extremely important part of any power system. Their primary function is to detect and
clear faults, which are inadvertent electrical connections – that is, short circuits – between system components at
different voltages. When faults occur, very high currents can result, typically 2-10 times as high as normal load
currents. Since power is proportional to I2, a great deal of energy can be delivered to unintended recipients in
a very short time. The goal of protection systems is to isolate and de-energize faults before they can harm personnel
or cause serious damage to equipment. Note that protection systems are designed to protect the power
system itself, rather than end-user equipment.