The 2026 HVDC pipeline includes Europe’s roughly 111 GW of committed offshore grid connections by 2035 and U.S. projects rated at 525 kV and multi-gigawatt scale.
Pipeline value depends more on project maturity, route rights, converter technology and cable supply than on a single global gigawatt total.
HVDC pipeline capacity spans 2.1 GW to 111 GW
Europe’s offshore pipeline commits approximately 111 GW of capacity to grid connection by 2035, and projects more than 80 km offshore generally require HVDC [S5]. That figure is a regional commitment rather than a verified worldwide construction total for 2026.
The U.S. project list includes Pinal County, Arizona, with listed converter ratings of 880 MW, 525 MW and 3,000 MW, linked to a 3,500 MW wind project and carrying a 2026 entry [S1]. SOO Green is a separate 2.1 GW Midwest HVDC scheme using a 525 kV line, converter stations at both ends and an approximately 350-mile underground route [S2].
Newton-Evans describes a handful of U.S. HVDC projects as approaching construction or planned for 2026–2028, with several more awaiting routing approvals and funding [S3]. The defensible conclusion is not one exact 2026 global pipeline total, but a segmented set of regional commitments, announced projects and pre-construction schemes.
SOO Green shows how route control unlocks 2.1 GW
SOO Green secured all route rights through a final municipal franchise agreement in Bellevue, Iowa, advancing the 2.1 GW project toward construction [S2]. The route runs about 350 miles underground within railroad rights of way from Mason City, Iowa, to Yorkville, Illinois, with converter stations at each end [S2].
The project is bidirectional and is designed to move wind and solar power, with storage smoothing the mix, from the Midcontinent Independent System Operator to PJM [S2]. Developers include energyRe and Copenhagen Infrastructure Partners, with Siemens Energy, Jingoli Power, Prysmian Group and PPL Corp. as partners [S2].
The project had been under development for about 12 years as of September 2025, illustrating the schedule exposure created by long-distance transmission rights, environmental review and network approvals [S2]. In the United States, project cost varies with rating, route length, overhead or underground construction, land expense and required AC network improvements at each terminal [S3].
Converter, cable and civil scope drive procurement
Converter stations and transmission cables are the two main cost components of an HVDC system [S3]. Equipment packages must be separated from total project value because a converter award, cable award and civil-works package cover different supplier scopes, with converter suppliers named for a U.S. market including Hitachi Energy and Siemens Energy [S3].
The U.S. HVDC equipment flow associated with converter stations was estimated at nearly USD 0.5 billion per year, including converter-station construction and maintenance activity [S3]. Individual U.S. projects identified for 2026–2028 were each expected to cost well over USD 1 billion, although only a portion of that total goes to converter-station suppliers [S3].
Newton-Evans also identifies GE Vernova, MEPPI and Toshiba as market participants with revenue flows in the millions of dollars across multi-year projects and maintenance of operating sites [S3]. The broader equipment context, including converter supply chains, cables and transformers, is examined in HVDC Market 2026: Converters, Cables and Transformers.
Overhead, underground and offshore routes need separate forecasts
Overhead schemes represented 51.8% of HVDC transmission market revenue in 2025, while submarine systems were forecast to grow at a 12.0% annual rate through 2035 as seabed export routes expanded [S5]. The 400–800 kV class represented 48.7% of installed capacity in 2025, and equipment above 800 kV was forecast to grow at 12.3% annually [S5].
For offshore wind, each gigawatt can require as much as 120 km of ±525 kV extruded cable, placing cable-factory capacity and long lead times near the center of project risk [S5]. By comparison, SOO Green uses a 525 kV direct-current line over roughly 350 miles of underground route [S2]. Those cases are not interchangeable, because an underground onshore corridor has different excavation, access and thermal conditions from a submarine export cable.
The Pinal County configuration also demonstrates why nameplate figures require care. Its listed 880 MW, 525 MW and 3,000 MW values are associated with separate station fields rather than one uniform transmission rating, and the project is combined with a 3,500 MW wind scheme [S1]. Pipeline capacity should therefore be checked at project, converter and system boundaries.
Selection depends on distance, power and project maturity
HVDC becomes more cost-effective as transmission distance increases, provided the route lacks a decisive AC advantage, while detailed evaluation is needed when economics rather than technical performance drives selection [S3]. SOO Green, Pinal County and Europe’s offshore portfolio therefore cannot be compared on capacity alone.
A four-part comparison captures the practical distinction. SOO Green combines 2.1 GW, 525 kV, 350 miles and underground construction in the United States [S2]. Pinal County lists 525–3,000 MW converter ratings, 880 MW at one station, 525 kV and a 2026 project entry in Arizona [S1]. Europe’s offshore pipeline carries approximately 111 GW of grid-connection commitments to 2035, with HVDC described as virtually required beyond 80 km from shore [S5].
HVDC is well suited to bulk transfer, grid interconnection, offshore renewable integration and urban infeed, while the 2025 market was segmented below 400 kV, 400–800 kV and above 800 kV [S5]. It is not the default choice for every network expansion. Short routes, modest transfers or projects dominated by local network reinforcement can favor AC, and projects without route approval or committed funding remain pipeline risks rather than bankable capacity [S3].
Delivery constraints create schedule and supply exposure
Each U.S. project in the 2026–2028 outlook was expected to cost more than USD 1 billion, while projects on the drawing board still required routing approvals and funding from multiple parties [S3]. Since 2021, Plains and Eastern Clean Energy Link, Rock Island Clean Line and Juan de Fuca Cable HVDC had been cancelled or indefinitely postponed, and Clean Path New York was shelved by April 2026 [S3].
Cable and converter supply are additional constraints. European suppliers were reported to have order backlogs extending beyond 2030, while offshore wind exports require long lengths of high-voltage extruded cable [S5]. Converter projects also depend on supplier engineering, grid studies, terminal works and compatible AC network reinforcement, so converter award dates cannot be treated as commissioning dates.
Conventional project risks also include permitting, interconnection rights, financing, land acquisition, construction access and route changes. SOO Green’s roughly 12-year development period shows that commercial and regulatory progress can take longer than equipment procurement [S2]. A pipeline analysis should separate announced capacity, permitted capacity, financed capacity, awarded equipment and energized capacity.
Standards and procurement checks close the estimate gap
Project evaluation should record nominal voltage, transmission capacity, route length, route type, converter configuration, target year, regulatory status and network counterparty. SOO Green provides a documented benchmark at 2.1 GW, 525 kV and approximately 350 miles, while Pinal County requires interpretation of multiple converter and generation fields [S1][S2].
Hydrogen pipeline comparison remains relevant for very long-distance variable renewable energy transport. A life-cycle analysis found hydrogen pipelines cost-competitive with HVDC at 1,000 miles using 2030 technology, with the hydrogen option adding energy-storage capability [S4]. That result does not remove HVDC from the 2026 pipeline; it sets a long-distance alternative against which developers and system planners can test project economics.
Two trackable signals offer a practical update path. The first is the conversion of announced European offshore capacity into regulated and awarded projects. The second is US route approval, financing and equipment awards for 2.1 GW SOO Green and other schemes targeted for 2026–2028, where annual converter-related equipment flows are already running near USD 0.5 billion [S2][S3].