{"id":1013657,"date":"2026-04-21T13:25:38","date_gmt":"2026-04-21T16:25:38","guid":{"rendered":"https:\/\/www.psr-inc.com\/analytics-report\/post\/quantifying-the-value-of-transmission-flexibility-the-hvdc-link-upgrade-in-new-zealand\/"},"modified":"2026-04-23T11:39:54","modified_gmt":"2026-04-23T14:39:54","slug":"quantifying-the-value-of-transmission-flexibility-the-hvdc-link-upgrade-in-new-zealand","status":"publish","type":"analytics_post","link":"https:\/\/www.psr-inc.com\/en\/analytics-report\/post\/quantifying-the-value-of-transmission-flexibility-the-hvdc-link-upgrade-in-new-zealand\/","title":{"rendered":"Quantifying the value of transmission flexibility: the HVDC link upgrade in New Zealand"},"content":{"rendered":"
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Introduction<\/span><\/h1><\/h2>\n\n

Transmission infrastructure plays a central role in enabling modern power systems to operate efficiently under increasing uncertainty. In hydro-dominated systems with geographically concentrated resources, transmission capacity is particularly valuable because it allows energy to move between regions with different supply and demand characteristics.<\/p>\n\n

New Zealand is a clear example of this dynamic. The country\u2019s electricity system is divided between the hydro-rich South Island <\/strong>and the demand-dominated North Island<\/strong>, which relies more heavily on geothermal and thermal generation. The two systems are interconnected by a High Voltage Direct Current (HVDC) link that enables large-scale power transfers between islands.<\/p>\n\n

Transpower, the national transmission system operator, has been evaluating long-term reinforcement options for this interconnection through the HVDC Link Upgrade Programme\u00b3<\/strong>. The analysis presented in \u201cAttachment 6 \u2013 Benefits modelling\u201d assesses the economic and operational benefits of upgrading the submarine HVDC cables and associated equipment.<\/p>\n<\/div>

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To support this evaluation, the study used a detailed stochastic simulation framework based on OptGen\u2013SDDP, enabling the quantification of system benefits across a wide range of future conditions.<\/p>\n\n

This question also reflects ongoing changes in the generation mix. Over the last decade, wind and solar have expanded steadily and, in several months of the year, already represent a non-negligible share of supply. Together, they have recently accounted for about 11% of electricity generation, and official long-term projections indicate continued growth over the next decade. Unlike hydrological uncertainty, which unfolds over seasonal and interannual horizons, renewable uncertainty is driven by stronger short-term volatility and limited controllability. In this context, hydro reservoirs gain additional importance as sources of operational flexibility, helping absorb renewable variability and limit reliance on costly thermal generation during stressed periods.<\/p>\n\n

The results highlight the critical role of inter-regional transmission capacity in improving system efficiency, supporting renewable integration, and maintaining reliability in hydro-dependent electricity systems.<\/p>\n\n

This study evaluates whether upgrading the HVDC Link would deliver economic and operational benefits to the New Zealand power system from a holistic system perspective.<\/p>\n\n

\u00b3The entire \u201cHVDC Link Upgrade Programme \u2013 Major Capex Proposal (Stage 1) \u2013 Attachment 6: Benefits modelling\u201d report is available at: https:\/\/static.transpower.co.nz\/public\/uncontrolled_docs\/HVDC%20MCP%20-%20Attachment%206%20-%20Benefits%20modelling.pdf<\/p>\n\n

Modeling Framework: Integrated Planning & Operation Simulation<\/span><\/h1><\/h2>\n\n

The benefits assessment combines generation expansion planning<\/strong> and stochastic system operation modeling<\/strong>.<\/p>\n\n

OptGen is used to determine cost-optimal investment pathways for generation technologies over the long-term planning horizon. This expansion modeling establishes the evolution of the generation mix and ensures that operational simulations are consistent with economically realistic future systems.<\/p>\n\n

SDDP is then used to simulate the operation of the electricity system under uncertainty. The model determines optimal dispatch decisions across thousands of possible future scenarios while explicitly representing hydro reservoir dynamics, renewable variability, and demand uncertainty.<\/p>\n\n

For this study, dispatch simulations were conducted with hourly temporal resolution over the period 2023\u20132060<\/strong>, allowing the model to capture detailed operational patterns and short-term variability in renewable generation and demand.<\/p>\n\n

Hydrological uncertainty plays a particularly important role in the New Zealand system. To represent this variability, SDDP uses synthetic inflow sequences derived from historical data<\/strong>, preserving seasonal patterns and correlations between hydro plants.<\/p>\n\n

This stochastic framework enables the evaluation of transmission investments not only under average conditions, but also across a wide range of hydrological outcomes.<\/p>\n\n

Representation of the HVDC Interconnection<\/span><\/h1><\/h2>\n\n

The HVDC link between the North and South Islands is explicitly represented in the model through transfer limits, losses, and operational characteristics.<\/p>\n\n

In the current configuration, the interconnection allows transfers of approximately 1,071 MW northward and 762 MW southward<\/strong>, reflecting operational constraints associated with reactive support equipment at the Haywards converter station.<\/p>\n\n

Following the commissioning of additional reactive support in 2027, the transfer capacity increases to 1,200 MW northward and 950 MW southward<\/strong>.<\/p>\n\n

The study evaluates three long-term infrastructure strategies:<\/p>\n\n