Report on 2 March 2017 South Island AUFLS Event

On 2 March 2017, New Zealand experienced a major and complex power system event. The event resulted in the South Island power system splitting into two separate systems. Approximately 120 MW (16%) of electricity used by consumers in the upper part of the South Island was disconnected for up to 90 minutes.  

This report provides the findings from the System Operator's investigation into the event.

Transmission Planning Report - July 2017

Transpower regularly publishes a Transmission Planning Report (TPR) which details the grid asset capability over the next 15 years.

We have evolved our TPR this year to include a Grid Enhancement Approach. These new sections, in each regional chapter, provide more detail on active and potential investment investigations, linking the current investigation status to our planning processes and portfolio funding.

Market impact assessment from changes to HVDC cost allocation

The methodology to allocate the HVDC costs to South Island (SI) generators was changed in 2015. This change involved transitioning from the peak-based metric (HAMI) to an average-based metric (SIMI) from the 2017/18 pricing year (PY). The allocation based on HAMI resulted in a strong incentive for SI generators to maintain generation below established HAMI levels (HAMI limits) thus avoiding increased allocation of HVDC costs. The change to SIMI was intended to reduce this incentive, thus increasing the availability of SI generation capacity.

Ten Year Forecast of Fault Levels

This publication presents an update to the ten year forecast fault levels report. The Connection Code contained in Schedule 8 to the Benchmark Agreement requires Transpower to publish a ten year forecast of the expected fault levels at each customer point of service annually.

Transpower last published the Ten Year Forecast of Fault Levels in September 2015.



HVDC bi-pole trip and change to under frequency reserve risk: technical commentary

On 11 December Transpower’s HVDC equipment suffered a bi-pole trip while transferring 90 MW to the North Island. The cause was unexpected and, while an explanation was quickly found, it was deemed necessary to change the risk treatment of bi-pole trip risk from ECE to CE until a fix could be determined. This change in risk status, with consequent market impacts, lasted 8 days until an interim fix to the faulted assets could be implemented.  A permanent fix will be developed and implemented in 2016.