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Long distance HVDC lines carrying hydroelectricity from Canada's Nelson river to this station where it is converted to AC for use in Winnipeg's local grid

A high-voltage, direct current (HVDC) electric power transmission system uses direct current for the bulk transmission of electrical power, in contrast with the more common alternating current systems. For long-distance distribution, HVDC systems are less expensive and suffer lower electrical losses. For shorter distances, the higher cost of DC conversion equipment compared to an AC system may be warranted where other benefits of direct current links are useful.

The modern form of HVDC transmission uses technology developed extensively in the 1930s in Sweden at ASEA. Early commercial installations included one in the Soviet Union in 1951 between Moscow and Kashira, and a 10-20 MW system between Gotland and mainland Sweden in 1954.[1] The longest HVDC link in the world is currently the Inga-Shaba 1,700 km (1,100 mi) 600 MW link connecting the Inga Dam to the Shaba copper mine, in the Democratic Republic of Congo.

HVDC interconnections in western Europe - red are existing links, green are under construction, and blue are proposed. Many of these transfer power from renewable sources such as hydro and wind. For names, see also the annotated version.


High voltage transmission

High voltage is used for transmission to reduce the energy lost in the resistance of the wires. For a given quantity of power transmitted, higher voltage reduces the transmission power loss. Power in a circuit is proportional to the current, but the power lost as heat in the wires is proportional to the square of the current. However, power is also proportional to voltage, so for a given power level, higher voltage can be traded off for lower current. Thus, the higher the voltage, the lower the power loss. Power loss can also be reduced by reducing resistance, commonly achieved by increasing the diameter of the conductor; but larger conductors are heavier and more expensive.

High voltages cannot be easily used in lighting and motors, and so transmission-level voltage must be reduced to values compatible with end-use equipment. The transformer, which only works with alternating current, is an efficient way to change voltages. The competition between the DC of Thomas Edison and the AC of Nikola Tesla and George Westinghouse was known as the War of Currents, with AC emerging victorious. Practical manipulation of DC voltages only became possible with the development of high power electronic devices such as mercury arc valves and later semiconductor devices, such as thyristors, insulated-gate bipolar transistors (IGBTs), high power capable MOSFETs (power metal–oxide–semiconductor field-effect transistors) and gate turn-off thyristors (GTOs).

History of HVDC transmission

Schematic diagram of a Thury HVDC transmission system

The first long-distance transmission of electric power was demonstrated using direct current in 1882 at the Miesbach-Munich Power Transmission, but only 2.5 kW was transmitted. An early method of high-voltage DC transmission was developed by the Swiss engineer Rene Thury[2] and his method was put into practice by 1889 in Italy by the Acquedotto De Ferrari-Galliera company. This system used series-connected motor-generator sets to increase voltage. Each set was insulated from ground and driven by insulated shafts from a prime mover. The line was operated in constant current mode, with up to 5,000 volts on each machine, some machines having double commutators to reduce the voltage on each commutator. This system transmitted 630 kW at 14 kV DC over a distance of 120 km.[3][4] The Moutiers-Lyon system transmitted 8,600 kW of hydroelectric power a distance of 124 miles, including 6 miles of underground cable. The system used eight series-connected generators with dual commutators for a total voltage of 150,000 volts between the poles, and ran from about 1906 until 1936. Fifteen Thury systems were in operation by 1913 [5] Other Thury systems operating at up to 100 kV DC operated up to the 1930s, but the rotating machinery required high maintenance and had high energy loss. Various other electromechanical devices were tested during the first half of the 20th century with little commercial success.[6]

One conversion technique attempted for conversion of direct current from a high transmission voltage to lower utilization voltage was to charge series-connected batteries, then connect the batteries in parallel to serve distribution loads.[7] While at least two commercial installations were tried around the turn of the 20th century, the technique was not generally useful owing to the limited capacity of batteries, difficulties in switching between series and parallel connections, and the inherent energy inefficiency of a battery charge/discharge cycle.

HVDC in 1971: this 150 kV mercury arc valve converted AC hydropower voltage for transmission to distant cities from Manitoba Hydro generators.

The grid controlled mercury arc valve became available for power transmission during the period 1920 to 1940. Starting in 1932, General Electric tested mercury-vapor valves and a 12 kV DC transmission line, which also served to convert 40 Hz generation to serve 60 Hz loads, at Mechanicville, New York. In 1941, a 60 MW, +/-200 kV, 115 km buried cable link was designed for the city of Berlin using mercury arc valves (Elbe-Project), but owing to the collapse of the German government in 1945 the project was never completed.[8] The nominal justification for the project was that, during wartime, a buried cable would be less conspicuous as a bombing target. The equipment was moved to the Soviet Union and was put into service there.[9]

Introduction of the fully-static mercury arc valve to commercial service in 1954 marked the beginning of the modern era of HVDC transmission. A HVDC-connection was constructed by ASEA between the mainland of Sweden and the island Gotland. Mercury arc valves were common in systems designed up to 1975, but since then, HVDC systems use only solid-state devices. From 1975 to 2000, line-commutated converters (LCC) using thyristor valves were relied on. According to experts such as Vijay Sood, the next 25 years may well be dominated by force commutated converters, beginning with capacitor commutative converters (CCC) followed by self commutating converters which have largely supplanted LCC use.[10] Since use of semiconductor commutators, hundreds of HVDC sea-cables have been laid and worked with high reliability, usually better than 96% of the time.

Advantages of HVDC over AC transmission

Bipolar system pylons of the Baltic-Cable-HVDC in Sweden

The advantage of HVDC is the ability to transmit large amounts of power over long distances with lower capital costs and with lower losses than AC. Depending on voltage level and construction details, losses are quoted as about 3% per 1,000 km.[11] High-voltage direct current transmission allows efficient use of energy sources remote from load centers.

In a number of applications HVDC is more effective than AC transmission. Examples include:

  • Undersea cables, where high capacitance causes additional AC losses. (e.g., 250 km Baltic Cable between Sweden and Germany[12] and the 600 km NorNed cable between Norway and the Netherlands)
  • Endpoint-to-endpoint long-haul bulk power transmission without intermediate 'taps', for example, in remote areas
  • Increasing the capacity of an existing power grid in situations where additional wires are difficult or expensive to install
  • Power transmission and stabilization between unsynchronised AC distribution systems
  • Connecting a remote generating plant to the distribution grid, for example Nelson River Bipole
  • Stabilizing a predominantly AC power-grid, without increasing prospective short circuit current
  • Reducing line cost. HVDC needs fewer conductors as there is no need to support multiple phases. Also, thinner conductors can be used since HVDC does not suffer from the skin effect
  • Facilitate power transmission between different countries that use AC at differing voltages and/or frequencies
  • Synchronize AC produced by renewable energy sources

Long undersea high voltage cables have a high electrical capacitance, since the conductors are surrounded by a relatively thin layer of insulation and a metal sheath. The geometry is that of a long co-axial capacitor. Where alternating current is used for cable transmission, this capacitance appears in parallel with load. Additional current must flow in the cable to charge the cable capacitance, which generates additional losses in the conductors of the cable. Additionally, there is a dielectric loss component in the material of the cable insulation, which consumes power.
When, however, direct current is used, the cable capacitance is only charged when the cable is first energized or when the voltage is changed; there is no steady-state additional current required. For a long AC undersea cable, the entire current-carrying capacity of the conductor could be used to supply the charging current alone. This limits the length of AC cables. DC cables have no such limitation. Although some DC leakage current continues to flow through the dielectric, this is very small compared to the cable rating.

HVDC can carry more power per conductor because, for a given power rating, the constant voltage in a DC line is lower than the peak voltage in an AC line. In AC power, the root mean square (RMS) voltage measurement is considered the standard, but RMS is only about 71% of the peak voltage. The peak voltage of AC determines the actual insulation thickness and conductor spacing. Because DC operates at a constant maximum voltage, this allows existing transmission line corridors with equally sized conductors and insulation to carry 100% more power into an area of high power consumption than AC, which can lower costs.

Because HVDC allows power transmission between unsynchronized AC distribution systems, it can help increase system stability, by preventing cascading failures from propagating from one part of a wider power transmission grid to another. Changes in load that would cause portions of an AC network to become unsynchronized and separate would not similarly affect a DC link, and the power flow through the DC link would tend to stabilize the AC network. The magnitude and direction of power flow through a DC link can be directly commanded, and changed as needed to support the AC networks at either end of the DC link. This has caused many power system operators to contemplate wider use of HVDC technology for its stability benefits alone.


The disadvantages of HVDC are in conversion, switching, control, availability and maintenance.

The required static inverters are expensive and have limited overload capacity. At smaller transmission distances the losses in the static inverters may be bigger than in an AC transmission line. The cost of the inverters may not be offset by reductions in line construction cost and lower line loss. With two exceptions, all former mercury rectifiers worldwide have been dismantled or replaced by thyristor units. Pole 1 of the HVDC scheme between the North and South Islands of New Zealand still uses mercury arc rectifiers, as does Pole 1 of the Vancouver Island link in Canada.

In contrast to AC systems[citation needed], realizing multiterminal systems is complex, as is expanding existing schemes to multiterminal systems. Controlling power flow in a multiterminal DC system requires good communication between all the terminals; power flow must be actively regulated by the inverter control system instead of the inherent impedance and phase angle properties of the transmission line.[13] Multi-terminal lines are rare. One is in operation at the Hydro Québec - New England transmission from Radisson to Sandy Pond.[14] Another example is the Sardinia-mainland Italy link which was modified in 1989 to also provide power to the island of Corsica.[15]

HVDC is less reliable and has lower availability than AC systems, mainly due to the extra conversion equipment. Single pole systems have availability of about 98.5%, with about a third of the downtime unscheduled due to faults. Fault redundant bipole systems provide high availability for 50% of the link capacity, but availability of the full capacity is about 97% to 98%.[16]

High voltage DC circuit breakers are difficult to build because some mechanism must be included in the circuit breaker to force current to zero, otherwise arcing and contact wear would be too great to allow reliable switching.

Operating a HVDC scheme requires many spare parts to be kept, often exclusively for one system as HVDC systems are less standardized than AC systems and technology changes faster.

Costs of high voltage DC transmission

Normally manufacturers such as AREVA, Siemens and ABB do not state specific cost information of a particular project since this is a commercial matter between the manufacturer and the client.

Costs vary widely depending on the specifics of the project such as power rating, circuit length, overhead vs. underwater route, land costs, and AC network improvements required at either terminal. A detailed evaluation of DC vs. AC cost may be required where there is no clear technical advantage to DC alone and only economics drives the selection.

However some practitioners have given out some information that can be reasonably well relied upon:

For an 8 GW 40 km link laid under the English Channel, the following are approximate primary equipment costs for a 2000 MW 500 kV bipolar conventional HVDC link (exclude way-leaving, on-shore reinforcement works, consenting, engineering, insurance, etc.)
  • Converter stations ~£110M
  • Subsea cable + installation ~£1M/km

So for an 8 GW capacity between England and France in four links, little is left over from £750M for the installed works. Add another £200–300M for the other works depending on additional onshore works required.[17]

Rectifying and inverting


Two of three thyristor valve stacks used for long distance transmission of power from Manitoba Hydro dams

Early static systems used mercury arc rectifiers, which were unreliable. Two HVDC systems using mercury arc rectifiers are still in service (As of 2008). The thyristor valve was first used in HVDC systems in the 1960s. The thyristor is a solid-state semiconductor device similar to the diode, but with an extra control terminal that is used to switch the device on at a particular instant during the AC cycle. The insulated-gate bipolar transistor (IGBT) is now also used and offers simpler control and reduced valve cost.

Because the voltages in HVDC systems, up to 800 kV in some cases, exceed the breakdown voltages of the semiconductor devices, HVDC converters are built using large numbers of semiconductors in series.

The low-voltage control circuits used to switch the thyristors on and off need to be isolated from the high voltages present on the transmission lines. This is usually done optically. In a hybrid control system, the low-voltage control electronics sends light pulses along optical fibres to the high-side control electronics. Another system, called direct light triggering, dispenses with the high-side electronics, instead using light pulses from the control electronics to switch light-triggered thyristors (LTTs).

A complete switching element is commonly referred to as a valve, irrespective of its construction.

Rectifying and inverting systems

Rectification and inversion use essentially the same machinery. Many substations are set up in such a way that they can act as both rectifiers and inverters. At the AC end a set of transformers, often three physically separate single-phase transformers, isolate the station from the AC supply, to provide a local earth, and to ensure the correct eventual DC voltage. The output of these transformers is then connected to a bridge rectifier formed by a number of valves. The basic configuration uses six valves, connecting each of the three phases to each of the two DC rails. However, with a phase change only every sixty degrees, considerable harmonics remain on the DC rails.

An enhancement of this configuration uses 12 valves (often known as a twelve-pulse system). The AC is split into two separate three phase supplies before transformation. One of the sets of supplies is then configured to have a star (wye) secondary, the other a delta secondary, establishing a thirty degree phase difference between the two sets of three phases. With twelve valves connecting each of the two sets of three phases to the two DC rails, there is a phase change every 30 degrees, and harmonics are considerably reduced.

In addition to the conversion transformers and valve-sets, various passive resistive and reactive components help filter harmonics out of the DC rails.


Monopole and earth return

Block diagram of a monopole system with earth return

In a common configuration, called monopole, one of the terminals of the rectifier is connected to earth ground. The other terminal, at a potential high above, or below, ground, is connected to a transmission line. The earthed terminal may or may not be connected to the corresponding connection at the inverting station by means of a second conductor.

If no metallic conductor is installed, current flows in the earth between the earth electrodes at the two stations. Therefore it is a type of single wire earth return. The issues surrounding earth-return current include:

  • Electrochemical corrosion of long buried metal objects such as pipelines
  • Underwater earth-return electrodes in seawater may produce chlorine or otherwise affect water chemistry.
  • An unbalanced current path may result in a net magnetic field, which can affect magnetic navigational compasses for ships passing over an underwater cable.

These effects can be eliminated with installation of a metallic return conductor between the two ends of the monopolar transmission line. Since one terminal of the converters is connected to earth, the return conductor need not be insulated for the full transmission voltage which makes it less costly than the high-voltage conductor. Use of a metallic return conductor is decided based on economic, technical and environmental factors.[18]

Modern monopolar systems for pure overhead lines carry typically 1,500 MW.[19] If underground or underwater cables are used, the typical value is 600 MW.

Most monopolar systems are designed for future bipolar expansion. Transmission line towers may be designed to carry two conductors, even if only one is used initially for the monopole transmission system. The second conductor is either unused, used as electrode line or connected in parallel with the other (as in case of Baltic-Cable).


Block diagram of a bipolar system that also has an earth return

In bipolar transmission a pair of conductors is used, each at a high potential with respect to ground, in opposite polarity. Since these conductors must be insulated for the full voltage, transmission line cost is higher than a monopole with a return conductor. However, there are a number of advantages to bipolar transmission which can make it the attractive option.

  • Under normal load, negligible earth-current flows, as in the case of monopolar transmission with a metallic earth-return. This reduces earth return loss and environmental effects.
  • When a fault develops in a line, with earth return electrodes installed at each end of the line, approximately half the rated power can continue to flow using the earth as a return path, operating in monopolar mode.
  • Since for a given total power rating each conductor of a bipolar line carries only half the current of monopolar lines, the cost of the second conductor is reduced compared to a monopolar line of the same rating.
  • In very adverse terrain, the second conductor may be carried on an independent set of transmission towers, so that some power may continue to be transmitted even if one line is damaged.

A bipolar system may also be installed with a metallic earth return conductor.

Bipolar systems may carry as much as 3,200 MW at voltages of +/-600 kV. Submarine cable installations initially commissioned as a monopole may be upgraded with additional cables and operated as a bipole.

A block diagram of a bipolar HVDC transmission system, between two stations designated A and B. AC - represents an alternating current network CON - represents a converter valve, either rectifier or inverter, TR represents a power transformer, DCTL is the direct-current transmission line conductor, DCL is a direct-current filter inductor, BP represents a bypass switch, and PM represent power factor correction and harmonic filter networks required at both ends of the link. The DC transmission line may be very short in a back-to-back link, or extend hundreds of miles (km) overhead, underground or underwater. One conductor of the DC line may be replaced by connections to earth ground.

Back to back

A back-to-back station (or B2B for short) is a plant in which both static inverters and rectifiers are in the same area, usually in the same building. The length of the direct current line is kept as short as possible. HVDC back-to-back stations are used for

  • coupling of electricity mains of different frequency (as in Japan; and the GCC interconnection between UAE [50Hz] and Saudi Arabia [60Hz] under construction in ±2009-2011)
  • coupling two networks of the same nominal frequency but no fixed phase relationship (as until 1995/96 in Etzenricht, Dürnrohr and Vienna).
  • different frequency and phase number (for example, as a replacement for traction current converter plants)

The DC voltage in the intermediate circuit can be selected freely at HVDC back-to-back stations because of the short conductor length. The DC voltage is as low as possible, in order to build a small valve hall and to avoid series connections of valves. For this reason at HVDC back-to-back stations valves with the highest available current rating are used.

Systems with transmission lines

The most common configuration of an HVDC link is two inverter/rectifier stations connected by an overhead power line. This is also a configuration commonly used in connecting unsynchronised grids, in long-haul power transmission, and in undersea cables.

Multi-terminal HVDC links, connecting more than two points, are rare. The configuration of multiple terminals can be series, parallel, or hybrid (a mixture of series and parallel). Parallel configuration tends to be used for large capacity stations, and series for lower capacity stations. An example is the 2,000 MW Quebec - New England Transmission system opened in 1992, which is currently the largest multi-terminal HVDC system in the world.[20]

Tripole: current-modulating control

A scheme patented in 2004 (Current modulation of direct current transmission lines) is intended for conversion of existing AC transmission lines to HVDC. Two of the three circuit conductors are operated as a bipole. The third conductor is used as a parallel monopole, equipped with reversing valves (or parallel valves connected in reverse polarity). The parallel monopole periodically relieves current from one pole or the other, switching polarity over a span of several minutes. The bipole conductors would be loaded to either 1.37 or 0.37 of their thermal limit, with the parallel monopole always carrying +/- 1 times its thermal limit current. The combined RMS heating effect is as if each of the conductors is always carrying 1.0 of its rated current. This allows heavier currents to be carried by the bipole conductors, and full use of the installed third conductor for energy transmission. High currents can be circulated through the line conductors even when load demand is low, for removal of ice.

As of 2005, no tri-pole conversions are in operation, although a transmission line in India has been converted to bipole HVDC.

Corona discharge

Corona discharge is the creation of ions in a fluid (such as air) by the presence of a strong electric field. Electrons are torn from neutral air, and either the positive ions or the electrons are attracted to the conductor, while the charged particles drift. This effect can cause considerable power loss, create audible and radio-frequency interference, generate toxic compounds such as oxides of nitrogen and ozone, and bring forth arcing.

Both AC and DC transmission lines can generate coronas, in the former case in the form of oscillating particles, in the latter a constant wind. Due to the space charge formed around the conductors, an HVDC system may have about half the loss per unit length of a high voltage AC system carrying the same amount of power. With monopolar transmission the choice of polarity of the energized conductor leads to a degree of control over the corona discharge. In particular, the polarity of the ions emitted can be controlled, which may have an environmental impact on particulate condensation. (particles of different polarities have a different mean-free path.) Negative coronas generate considerably more ozone than positive coronas, and generate it further downwind of the power line, creating the potential for health effects. The use of a positive voltage will reduce the ozone impacts of monopole HVDC power lines.



The of current-flow through HVDC rectifiers and inverters, their application in connecting unsynchronized networks, and their applications in efficient submarine cables mean that HVDC cables are often used at national boundaries for the exchange of power (in North America, HVDC connections divide much of Canada and the United States into several electrical regions that cross national borders, although the purpose of these connections is still to connect unsynchronized AC grids to each other). Offshore windfarms also require undersea cables, and their turbines are unsynchronized. In very long-distance connections between just two points, for example around the remote communities of Siberia, Canada, and the Scandinavian North, the decreased line-costs of HVDC also makes it the usual choice. Other applications have been noted throughout this article.

AC network interconnections

AC transmission lines can only interconnect synchronized AC networks that oscillate at the same frequency and in phase. Many areas that wish to share power have unsynchronized networks. The power grids of the UK, Northern Europe and continental Europe are not united into a single synchronized network. Japan has 50 Hz and 60 Hz networks. Continental North America, while operating at 60 Hz throughout, is divided into regions which are unsynchronised: East, West, Texas, Quebec, and Alaska. Brazil and Paraguay, which share the enormous Itaipu hydroelectric plant, operate on 60 Hz and 50 Hz respectively. However, HVDC systems make it possible to interconnect unsynchronized AC networks, and also add the possibility of controlling AC voltage and reactive power flow.

A generator connected to a long AC transmission line may become unstable and fall out of synchronization with a distant AC power system. An HVDC transmission link may make it economically feasible to use remote generation sites. Wind farms located off-shore may use HVDC systems to collect power from multiple unsynchronized generators for transmission to the shore by an underwater cable.

In general, however, an HVDC power line will interconnect two AC regions of the power-distribution grid. Machinery to convert between AC and DC power adds a considerable cost in power transmission. The conversion from AC to DC is known as rectification, and from DC to AC as inversion. Above a certain break-even distance (about 50 km for submarine cables, and perhaps 600–800 km for overhead cables), the lower cost of the HVDC electrical conductors outweighs the cost of the electronics.

The conversion electronics also present an opportunity to effectively manage the power grid by means of controlling the magnitude and direction of power flow. An additional advantage of the existence of HVDC links, therefore, is potential increased stability in the transmission grid.

Renewable electricity superhighways

A number of studies have highlighted the potential benefits of very wide area super grids based on HVDC since they can mitigate the effects of intermittency by averaging and smoothing the outputs of large numbers of geographically dispersed wind farms or solar farms.[21] Czisch's study concludes that a grid covering the fringes of Europe could bring 100% renewable power (70% wind, 30% biomass) at close to today's prices. There has been debate over the technical feasibility of this proposal[22] and the political risks involved in energy transmission across a large number of international borders.[23][23]

The construction of such green power superhighways is advocated in a white paper that was released by the American Wind Energy Association and the Solar Energy Industries Association[24]

In January 2009, the European Commission proposed €300 million to subsidize the development of HVDC links between Ireland, Britain, the Netherlands, Germany, Denmark, and Sweden, as part of a wider €1.2 billion package supporting links to offshore wind farms and cross-border interconnectors throughout Europe. Meanwhile the recently founded Union of the Mediterranean has embraced a Mediterranean Solar Plan to import large amounts of concentrating solar power into Europe from North Africa and the Middle East.[25]

Smaller scale use

The development of insulated gate bipolar transistors (IGBT) and gate turn-off thyristors (GTO) has made smaller HVDC systems economical. These may be installed in existing AC grids for their role in stabilizing power flow without the additional short-circuit current that would be produced by an additional AC transmission line. ABB manufacturer calls this concept "HVDC Light" and Siemens manufacturer calls a similar concept "HVDC PLUS" (Power Link Universal System). They have extended the use of HVDC down to blocks as small as a few tens of megawatts and lines as short as a few score kilometres of overhead line. The difference lies in the concept of the Voltage-Sourced Converter (VSC) technology whereas "HVDC Light" uses pulse width modulation and "HVDC PLUS" is based on multilevel switching.

Powerline Deicing

HVDC can be also used for powerline de-icing. See Levis De-Icer.

See also


General information
  1. ^ Narain G. Hingorani in IEEE Spectrum magazine, 1996.
  2. ^ Donald Beaty et al, "Standard Handbook for Electrical Engineers 11th Ed.", McGraw Hill, 1978
  3. ^ ACW's Insulator Info - Book Reference Info - History of Electrical Systems and Cables
  4. ^ R. M. Black The History of Electric Wires and Cables, Peter Perigrinus, London 1983 ISBN 086341 001 4 pages 94-96
  5. ^ Alfred Still, Overhead Electric Power Transmission, McGraw Hill, 1913 page 145, available from the Internet Archive
  6. ^ "Shaping the Tools of Competitive Power"
  7. ^ Thomas P. Hughes, Networks of Power
  8. ^ "HVDC TransmissionF"
  9. ^ IEEE - IEEE History Center
  10. ^ [|Vijay K. Sood]. HVDC and FACTS Controllers: Applications Of Static Converters In Power Systems. Springer-Verlag. p. 1. ISBN 978-1402078903. "The first 25 years of HVDC transmission were sustained by converters having mercury arc valves till the mid-1970s. The next 25 years till the year 2000 were sustained by line-commutated converters using thyristor valves. It is predicted that the next 25 years will be dominated by force-commutated converters [4]. Initially, this new force-commutated era has commenced with Capacitor Commutated Converters (CCC) eventually to be replaced by self-commutated converters due to the economic availability of high power switching devices with their superior characteristics." 
  11. ^ Siemens AG - Ultra HVDC Transmission System
  12. ^ ABB HVDC website
  13. ^ Donald G. Fink and H. Wayne Beaty (August 25, 2006). Standard Handbook for Electrical Engineers. McGraw-Hill Professional. p. 14-37 equation 14-56. ISBN 978-0071441469. 
  14. ^ ""HVDC multi-terminal system "". ABB Asea Brown Boveri. 2008-10-23. Retrieved 2008-12-12. 
  15. ^ The Corsican tapping: from design to commissioning tests of the third terminal of the Sardinia-Corsica-Italy HVDC Billon, V.C.; Taisne, J.P.; Arcidiacono, V.; Mazzoldi, F.; Power Delivery, IEEE Transactions on Volume 4, Issue 1, Jan. 1989 Page(s):794 - 799
  16. ^ "HVDC Classic reliability and availability". ABB. Retrieved 2009-09-11. 
  17. ^ Source works for a prominent UK engineering consultancy but has asked to remain anonymous and is a member of Claverton Energy Research Group
  18. ^ Basslink project
  19. ^ Siemens AG - HVDC website
  20. ^ ABB HVDC Transmission Québec - New England website
  21. ^ Gregor Czisch (2008-10-24). "Low Cost but Totally Renewable Electricity Supply for a Huge Supply Area – a European/Trans-European Example –" (pdf). 2008 Claverton Energy conference (University of Kassel). Retrieved 2008-07-16.  The paper was presented at the Claverton Energy conference in Bath, 24 October 2008. Paper Synopsis
  22. ^
  23. ^ a b
  24. ^
  25. ^ David Strahan "Green Grids" New Scientist 12 March 2009

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