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By Charles Rhodes, P.Eng., Ph.D.

Electricity transmission systems are used to efficiently transmit energy over long distances. Most of the transmitted energy is contained in the propagating electromagnetic field that is in close proximity to the transmission line conductors. Usually transmission lines are designed to guide energy from an energy source (usually a generator) to energy sinks (usually local distribution substations in municipalities). The direction of energy flow may change when there is a transmission connected energy storage system, because an energy storage system can alternately act as either an energy source or an energy sink. Bidirectional energy flow introduces numerous design complications.

Long distance electricity transmission is always done at a high voltage to minimize resistive line losses. Transmission circuits are usually designed for either balanced 3-wire 3-phase AC or balanced 2 wire DC operation.

Overhead balanced 3-wire 3-phase AC is most commonly used for power transmission because it provides relatively economical medium distance power transmission with capability of economical servicing of small communities along the transmission route. In commercial-industrial applications 3-phase is advantageous because it delivers power to the load at a constant rate and because it provides motors with excellent starting torque and speed control characteristics.

When the voltage and current wave forms are not exactly in phase then there is reflected power which increases transmission losses and reduces the transmission system's net power transfer capability.

Most galvanized steel lattice transmission towers support either one or two three phase AC transmission circuits. Often there is another smaller wire interconnecting the tops of the lattice towers that provides ground potential lightning protection. In Ontario typical phase to phase AC transmission voltages are 115 kV, 230 kV and 500 kV.

At 500 kV as compared to 230 kV the lattice pylons are taller (~ 198 feet), the insulators are longer, the conductor spacing is greater and the individual conductors are usually composed of 4 wires held in close proximity to each other by spreaders that control the interwire spacing. The purpose of this multi-wire conductor construction is to reduce the peak radial electric field at the conductor surface. With a single wire conductor at 500 kV RMS the peak radial electric field can cause ionization of the surrounding air. Such ionization causes radio interference and power loss.

The maximum power transfer capacity of one 500 kV 3-phase AC circuit is given by:
500 kV RMS X 1500 A RMS /conductor X 2 conductors = 1,500,000 kW = 1500 MW.
The third conductor in effect acts as a common return for the other two conductors.

Typically two three phase circuits are supported by a single line of pylons. Hence the maximum power capacity of an energy transmission corridor with a single line of pylons is:
2 circuits X 1500 MW / circuit = 3000 MW


The direct cost of building a two circuit 500 KV 3 phase AC transmission line, involving a single line of tall galvanized steel lattice pylons each supporting two circuits (six main conductors per lattice tower), through a rural area is typically about $5 million per mile ($3.1 million / km). The cost of building 500 kV transmission through an urban area is generally prohibitive due to the cost of right-of-way acquisition. In Ontario much of the 500 kV transmission runs parallel and/or adjacent to a major highway such as highways 400, 401, 403 or 407.

AC electricity transmission systems generally have distributed inductance and partially inductive loads such as transformers and motors that tend to cause a phase angle separation between the sinusoidal voltage and current waveforms on the same conductor. The cosine of this phase angle difference is known as the power factor. To maximize the power factor and hence maximize the power transmission capacity the phase angle between the voltage and current waveforms on the same conductor should be zero. Long AC transmission lines utilize capacitors and/or special generators to provide phase angle correction. This power factor correction methodology works well for point to point transmission lines but becomes very complex for branching circuits with variable branch loads that may be fed from different directions.

High voltage open wire AC transmission has the disadvantage that it cannot be routed under water. Above ground open wire 500 kV AC transmission conductors are usually supported by 65 m to 100 m high transmission pylons to minimize transmission loses due to the fringing electromagnetic field interacting with water in the ground.

DC transmission has the advantage that it permits twice as much power to be transmitted over the same towers, conductors and energy transmission corridor as are used for AC transmission. In an AC system the peak operating voltage rating is:
1.41 X 500 kV = 705 kV.

If the six conductors on a two circuit 500 kV AC tower are repurposed for DC operation there is potential for 3 balanced DC circuits. Each conductor can operate at 705 kV with respect to ground. On each DC circuit the differential voltage across the circuit is:
2 X 705 kV.
Hence the maximum power capacity becomes:
2 X 705 kV X 1500 A X 3 circuits = 6,345,000 kW
= 6,345 MW

DC transmission has the advantage that with sufficient cable insulation it can be routed under water.

DC transmission has the disadvantage that it requires equipment at the energy source end to convert the AC source power to DC for transmission and at the load end to convert the DC back to AC. This conversion equipment known as power inverters is expensive and is generally only used in circumstances when AC equipment is technically unsuitable. The three common circumstances are: very long transmission runs, underwater transmission runs and interconnection of separately controlled power zones.

A transmission system should be designed to have a 20% safety margin between maximum operating power and maximum capacity. However, in order for a transmission system to be reliable it must be possible to shut down any one transmission circuit for maintenance without shutting off load customer electricity service. Hence in a dual circuit configuration each circuit normally operates at less than 40% of maximum capacity so that during maintenance periods a single circuit can safely meet the maximum normal load of two circuits. If there are three parallel circuits that fraction can in principle be increased to 53%.

Sometimes there are four AC transmission circuits supported by two lines of pylons that follow the same path. In that case the normal power transmission per circuit can theoretically be increased from 40% of maximum circuit capacity to 60% of maximum circuit capacity while still maintaining the capability of taking any one circuit out of service for maintenance while not exceeding the 80% of maximum circuit capacity on the three remaining circuits. This arrangement realizes significant capital cost savings. However, there is a serious reliability tradeoff because an ice storm, earthquake, natural gas line rupture fire, etc. can easily take out all four circuits leaving no capacity to support even the most critical loads such as nuclear reactor cooling pumps and hospitals. Load customers are simply without electricity until the transmission is repaired or replaced. From a power system reliabiity perspective it is better to limit the number of circuits that follow a common corridor to two or three and accept the extra acquisition cost of a geographically separate redundant energy transmission corridor.

A major advantage of normally operating transmission lines at 40% of maximum power capacity is in improved efficiency. As a transmission line moves from 40% of maximum capacity to 80% of maximum capacity the energy loss via resistive heating quadruples. Thus an energy loss fraction that is normally 6% becomes 24%, which has a major impact on power system economics. This is another issue that is often not adequately appreciated by parties that question the need for redundant transmission lines.

It is generally accepted that the 2007 capital cost of rural dual circuit 500 kVAC transmission is about:
$3,600,000 / km-3000 MW peak = $1.20 / km-kW peak

Hence including redundancy for reliability the actual capital cost of 500 kV AC transmission is given by:
$1.20 / km-kW peak X (1 / 0.5) X (1 / 0.8) = $3.00 / km-kW peak

The corresponding annual blended cost of interest, capital amortization and maintenance for a transmission capacity of 1 kW is given by:
0.2 / year X $3.00 / km-kW = $.60 / kW-km-year

When the distance from the generator to the load is 1000 km, the annual cost of that transmission capacity becomes:
1000 km X $.60 / kW-km-year = $600.00 / kW-year

If as in the case of nuclear generation the generator capacity factor is 90%, this cost is amortized over:
0.9 X 8766 kWh / kW-year = 7889.4 kWh / kW-year
leading to a transmission cost per kWh of:
($600.00 / kW-year) / (7889.4 kWh / kW-year) = $.076 / kWh

If the transmission distance is 500 km the corresponding cost of nuclear electricity transmission is:
($300.00 / kW-year) / (7889.4 kWh / kW-year) = $0.038 / kWh

If as in the case of an unconstrained wind generation the generator capacity factor is only 30%, the cost of 1000 km transmission must be amortized over:
0.3 X 8766 kWh / kW-year = 2629.8 kWh / kW-year
leading to a transmission cost per kWh of:
($600.00 / kW-year) / (2629.8 kWh / kW-year) = $.228 / kWh
for 1000 km transmission.

If the transmission distance is only 500 km the corresponding cost of transmitting unconstrained wind energy is:
($300 / kW-year) / (2629.8 kWh / kW-year) = $0.114 / kWh

Note that the cost of transmission is proportional to the transmission distance and is inversely proportional to the generator capacity factor. This issue heavily impacts the cost of energy transmission to urban load centres from remote wind generation. The actual transmission path from a wind generator to a load center is from the generator to a hydraulic dam with energy storage and then to the load center. That transmission path is frequently very long. In addition there are energy losses due to transmission and energy storage inefficiency.

In Ontario DC transmission is primarily used for system isolation from neighbouring jurisdictions in the extreme east and extreme west to provide power system phase stability.

Ontario is geographically so large that if AC power propagated around the Great Lakes, following an uncertain route through the USA, without DC isolation, that AC power could come back to where it started with substantial phase error. Such phase error could cause uncontrollable electricity grid voltage and power oscillations.

In other jurisdictions DC is used for very long distance point to point power transmission and for transmitting power under major water bodies. For example, China has recentlly commissioned a DC transmission system to bring bulk Hydro power from western Mongolia to China's densely populated east coast. BC Hydro uses DC to transmit power from the BC mainland to Vancouver Island. Hydro Quebec uses DC to transmit power under the wider portions of the St. Lawrence River as well as to isolate itself from neighbouring jurisdictions. Newfoundland has a sub-ocean DC link from generation in Labrador.

Overhead DC has the advantage that with identical towers and cables it can operate at a higher power than AC while using only two main conductors per circuit instead of three. However, DC has the disadvantage that the termination equipment is relatively expensive. Hence it is usually not economical to tap DC bulk power transmission lines to service small communities along the DC transmission route.

A further complication with DC is a requirement for almost perfect conductor current balance. Unbalanced conductor currents in a DC transmission system cause a DC ground currents near terminal equipment that can corrode buried metal pipelines for kilometers around the terminal equipment.

An issue that is not adequately appreciated outside the electrical transmission community is that it is extremely difficult and expensive to design, install, operate and safely maintain a high voltage electricity transmission system in which bidirectional energy flow is permitted. It is far simpler and less expensive to design voltage regulation and electrical protection for a system with unidirectional energy flow. When a fault occurs that fault must be instantly isolated. Determining which isolation switches to trip is not so easy if bidirectional power flow is permitted. Each isolation switch must be sized for the lowest possible power source impedance, which is complicated and expensive to implement if the permitted power flow is bi-directional.

The simple solution to this issue is to divide generation into three classes, transmission connected generation, distribution connected generation and behind the meter generation. Transmission connected generation always exports power to the transmission system. Distribution connected generation should be controlled so that the distribution system is always a net load. Behind the meter generation should be controlled so that the load customer is always a net load. Thus net power always flows unidirectionally from transmission connected generators to the transmission system, from the transmission system to local distribution and from local distribution to load customers. This arrangement also improves safety for utility maintenance personnel.

There are parties that argue that bi-directional net energy flow should be permitted, that load customers should be paid for power exported to local distribution and distributors should be paid for power exported to transmission.

These parties fail to realize that in a non-fossil energy system kWh have little value and that electricity rates are dominated by kVA related costs. A sizable portion of the kVA cost is the cost of fault isolation switchgear which is much more expensive if bi-directional energy flow is permitted.

If load customers are permitted to generate the short circuit disconnect capacity of each branch isolation switch must be increased. Under present legislation there is no simple way of recovering the required switchgear upgrade costs.

If load customers are permitted to randomly export power to the local distribution grid, grid maintenace workers never have certainty that a particular power line is de-energized.

A large nuclear explosion near the surface of the sun or a nuclear explosion in Earths upper atmosphere can induce a major electro-magnetic pulse in extended power transmission lines and can directly destroy sensitive electronic equipment via the radiation pulse.

In principle sensitive electronic equipment can be suitably protected from the radiation pulse via a Faraday shield, which is simply a conducting metal enclosure.

The real problem is electromagnetic energy picked up by extended transmission lines that may be hundreds of km long. This energy pulse seeks to find ground and will destroy almost anything in its path.

Thus the conducted energy is an even greater problem than the radiated EMP energy. The EMP radiation can be attenuated by a suitable Faraday shield. However, any radial wire penetrating that shield is a path for high potential seeking ground.

This issue is normally addressed in electronic circuit design by use of high voltage shunt breakdown devices such as varistors. However, varistors used in practical circuit designs seldom have an energy pulse rating of more than a few joules. If a varistor is hit with too big a pulse it can fail open, in which case it will not protect against subsequent voltage pulses or it can fail closed in which case the circuit that it was protecting will not operate.

These same principles apply to lightning protection in power distribution.

The real threat in this matter is major power transformer failure. It is very difficult to design an efficient major 60 Hz AC power transformer that will stop the propagation of an extremely high common mode voltage pulse. Both the transformer primary and secondary must be insulated to withstand that voltage pulse. Normal lightning protection will not do because the propagating common mode voltage pulse will simply jump the transformer via the lightning protection.

In these circumstances the design objective should be to protect the transformers which are expensive and time consuming to replace and live with propagating pulse damage.

Then to withstand EMP we need terminal equipment that is Faraday shielded and that has the highest possible common mode voltage isolation that can be economically manufactured. In this respect the focus should be on local distribution transformers and their primary lightning protection and grounding. From a national security perspective it would be prudent for local distribution companies (LDCs) to maintain a large stock of such enhanced transformers as spares. The normal operating life of local distribution transformers is in excess of 50 years, so the LDCs will be in no hurry to make such a capital investment. Replacing these transformers in the normal course of events will likely take at least two human generations.

It would be prudent for energy system planners to realize that any workable plan for EMP protection likely involves re-specification and replacement of all the local distribution transformers and related lightning protection and grounding. There are likely more than 10 million such transformers in the USA. There would also need to be a replacement inventory of about 2 million spares. Increasing the common mode voltage isolation probably means making the transformers physically much larger.

The alternative is to face the reality that in the event of an EMP attack most of the line connected electrical and electronic devices in the affected area will be seriously damaged.

If the world public fully understood the scope and potential consequences of this problem they might forgive the USA for dropping a nuke on any party that threatens an EMP attack on the USA.

In our modern digital society the consequences of an EMP attack on grid connected devices would be extremely serious. There is something to be said for the merits of old fashioned mechanical control systems.

All the Canadian provinces adjoining the USA have transmission connections to the USA. Quebec has the highest voltage lines that operate at 735/765 kV. The Quebec links to the USA and to Ontario are DC isolated for electrical stability reasons. Quebec’s James Bay development is about 1500 miles north of the USA border and most of the Quebec load is near the Canadian/USA border so the lines do not have much load along the route. Quebec has 5 tie-lines to the USA with a total 4,250 MW capacity. Quebec also has 2,700 MW of tie-lines to Ontario and can wheel power through Ontario to New York and Michigan.

The Quebec interconnections and HVDC lines are described at the following link:
Quebec Tie Lines

A summarized description of all the Canadian connections to the USA are described at the following link:
Canadian Tie Lines

This web page last updated October 28, 2018.

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