There is a technology that can move several gigawatts between countries across thousands of kilometres, yet its oldest form depends on the receiving AC network being healthy enough to switch it off. That single operational constraint explains why some HVDC converter stations cost far less than others, why offshore wind developers choose a different architecture than long-distance hydro exporters, and why grid planners treat HVDC as a family of tools rather than one solution.
High-voltage direct current (HVDC) transmission has moved from a niche alternative for submarine cables to a central option in grid expansion. The two dominant converter families—line-commutated converters (LCC) and voltage-source converters (VSC)—look similar in single-line diagrams but differ in the power electronics they use, the network services they can provide, and the projects where they make sense. The distinction matters not because one is superior, but because choosing the wrong type can add cost, delay, or operational fragility.
A DC Choice Inside an AC Grid
AC transmission dominates nearly every synchronous grid because transformers make voltage conversion simple and cheap. HVDC earns its place only where AC’s limitations dominate: very long cable or overhead distances, submarine crossings, asynchronous grid interconnections, and situations where different frequency or phase-angle control is needed. AC cables also suffer from capacitance that charges and discharges with each cycle, producing reactive current that consumes cable capacity. Over tens of kilometres, this charging current can make AC cable transmission electrically impractical.
The first commercial HVDC installation—a 20 MW submarine link between the Swedish mainland and Gotland, commissioned in 1954—existed to move hydroelectric output across water at a scale and distance that AC cable capacitance would have made difficult. The converter technology of that first link relied on mercury arc valves, a predecessor to the thyristors used in modern LCC designs. That origin reveals the persistent logic of HVDC: it is not a universal replacement for AC, but a targeted tool for distances and boundaries where AC becomes electrically or economically unattractive.
The distinction between LCC and VSC did not exist at the outset; it emerged as power electronics advanced. LCC evolved from those early line-commutated designs, while VSC arrived commercially in the late 1990s with insulated-gate bipolar transistors (IGBTs), devices that can be turned on and off independently. That difference in switching capability is the core technical fork between the two families.
Line-Commutated Converters: The Workhorse of Bulk Transmission
Line-commutated converters use thyristors, high-power semiconductor switches that can be turned on by a gate signal but cannot be turned off by gate control. Instead, LCC relies on the AC voltage at the connected bus to reverse-bias each thyristor and force it to stop conducting. This is what “line-commutated” means: the commutation process is driven by the external AC voltage, not by the converter itself.
The practical consequence is that an LCC terminal needs a reasonably strong AC network at both ends. If the connected AC system voltage dips too low, commutation can fail, causing the converter to mis-fire or block. During a commutation failure, the DC current may briefly transfer to a bypass path, and the link may have to restart or ride through the disturbance. In a real sense, the converter borrows its turn-off signal from the grid it serves. That is not a remote theoretical concern; it is a design constraint that influences where LCC is deployed.
Because LCC cannot control its reactive power independently, every LCC terminal consumes reactive power from the AC grid—typically a large fraction of the active power transferred. Converter stations therefore include AC filter banks, shunt capacitors, or additional static var compensators to supply that reactive demand. The filters also deal with the significant harmonic currents produced by line commutation.
Where those requirements are manageable, LCC offers major advantages. It is the established technology for ultra-high-voltage direct current (UHVDC) links carrying several gigawatts over a thousand kilometres or more, such as bulk hydro and coal-by-wire corridors. LCC converter losses tend to be lower than VSC losses at equivalent voltage and power, and its converter station costs are typically lower per megawatt, partly because thyristor technology is older, cheaper and available at very high current and voltage ratings. This is why LCC remains the default for very long point-to-point bulk transmission between strong AC networks—for example, China’s long-distance UHVDC export corridors.
At the same time, LCC’s dependence on a strong AC grid makes it a poor choice for connecting isolated renewable plants, offshore wind farms, or weak island systems. It also cannot black start a network: if there is no AC voltage to commutate against, the converter cannot operate. In many modern grid reinforcement applications, those limitations point toward VSC.
Voltage-Source Converters: Flexibility at a Higher Price
Voltage-source converters use insulated-gate bipolar transistors, or IGBTs, which are controllable switches that can be turned on and off at high frequency. This self-commutation removes the dependence on an external AC voltage. A VSC can therefore operate into a weak grid or even a dead network, and it can independently control active and reactive power in all four quadrants of its capability curve.
That capability changes the role of the converter. Instead of consuming reactive power, a VSC terminal can be programmed to supply or absorb reactive power to support voltage at its point of connection. The same converter can provide synthetic inertia or fast frequency response, which is increasingly valuable as synchronous generators retire. In the absence of a live AC grid, a VSC can use its own switching to establish an AC voltage, making black start possible from the converter itself.
The trade-off is cost and complexity. IGBT-based valve designs are more expensive per megawatt than thyristor valves, and the switching process introduces higher losses, though modern modular multilevel converter (MMC) topologies have reduced those losses considerably. VSC converter stations also tend to have a smaller physical footprint for a given rating, partly because they require fewer passive AC filters, but the power electronics themselves represent a higher capital cost.
Offshore wind is the clearest commercially mature application for VSC. Submarine HVDC links connecting distant offshore wind farms to onshore grids routinely use VSC because the offshore AC network is weak, space is limited, and the converter needs to manage voltage and frequency without relying on a strong onshore grid. Multi-terminal HVDC systems and interconnections between asynchronous grids with limited short-circuit strength also favour VSC.
Where the Comparison Actually Bites
For a planner or developer, the LCC-versus-VSC decision rarely comes down to a preference for one semiconductor. It comes down to the AC network conditions, the required grid services, the distance, the power rating, and the acceptable capital and loss profile.
Some distinctions are particularly important in early project screening. The comparison becomes more nuanced when the AC network is not simply strong or weak. A converter terminal may sit in a network that is normally strong but loses short-circuit strength during outages or as synchronous machines retire. In that situation, an LCC link that once performed well can face repeated commutation failures or require additional synchronous condensers. Several existing HVDC links have been retrofitted with synchronous condensers or dynamic reactive support for exactly this reason.
- AC strength: LCC needs a strong AC grid at both ends; VSC can operate in weak networks and can start against a dead bus.
- Reactive power: LCC consumes reactive power and requires filters and compensation; VSC can supply reactive power and support voltage control.
- Harmonics: LCC generates low-frequency harmonics that require large AC filters; VSC uses higher-frequency switching and generally needs less filtering.
- Losses and cost: LCC tends to have lower converter station losses and lower capex per MW for large point-to-point links; VSC tends to cost more but avoids some AC reinforcement and filter costs.
- Reliability behaviour: LCC is mature and robust, but commutation failures can occur during AC disturbances; VSC avoids commutation failures but relies on more complex controls and power electronics.
The comparison becomes more nuanced when the AC network is not simply strong or weak. A converter terminal may sit in a network that is normally strong but loses short-circuit strength during outages or as synchronous machines retire. In that situation, an LCC link that once performed well can face repeated commutation failures or require additional synchronous condensers. Several existing HVDC links have been retrofitted with synchronous condensers or dynamic reactive support for exactly this reason.
This also means that a technology choice made decades ago can interact with the changing generation mix. A region that built LCC links around large thermal plants may find those links more challenging as those plants close and rotating inertia declines. That interaction is one of the less visible consequences of long planning timelines: converter types chosen today are likely to operate in a grid that differs substantially from the one that justified them.
What Utilities Should Watch
The current trajectory points toward both technologies remaining relevant, but in different parts of the grid. VSC costs have declined as IGBT manufacturing has matured and MMC designs have standardized, making VSC viable for a broader set of interconnectors and offshore links. At the same time, LCC retains an edge for very high-power, very long-distance overland corridors where the AC network at both ends is strong enough and the primary objective is moving bulk energy at low losses.
Hybrid and multi-terminal arrangements are beginning to blur the boundary. Some recent converter station designs combine LCC and VSC terminals on the same DC system, using LCC for the bulk transmission stage and VSC where weak AC conditions or black start capability are needed. This does not eliminate the fundamental differences; it assigns each technology to the role it handles best.
One near-term issue for planners is not the semiconductor choice but the surrounding infrastructure. Converter stations, DC cable manufacturing capacity, and HVDC switchgear all face supply-chain constraints. Even after a technology is selected, transmission infrastructure must be permitted, manufactured, and installed on schedules that rarely match the speed of generation connection requests. HVDC does not compress those planning timelines; in some cases, its specialist equipment lengthens them.
References
- International Energy Agency — context on global transmission expansion and HVDC deployment patterns.
- CIGRE — technical guidance on HVDC converter design, operation, and grid integration for LCC and VSC systems.
- IEEE — literature on power electronic converters, thyristor commutation, IGBT-based VSC technology, and modular multilevel converter topologies.
- ENTSO-E — grid connection frameworks and frequency support expectations for HVDC converter stations.
