Effect of Solar Pv on Voltage Management in New Zealand December 2017

EFFECT OF SOLAR PV ON VOLTAGE MANAGEMENT IN NEW ZEALAND DECEMBER 2017

TECHNICAL REPORT

Table of Contents

EXECUTIVE SUMMARY ...... VIII 1 INTRODUCTION ...... 1 1.1 Programme Overview ...... 1 1.2 The PV Generation Investigation Project ...... 2 1.3 The New Zealand power system...... 3 1.4 Impacts of PV generation on voltage management ...... 4 2 EXISTING VOLTAGE MANAGEMENT PRACTICES ...... 6 2.1 System Operation Principle Performance Obligation (PPO) in voltage management ...... 7 2.2 Voltage management ...... 7 2.3 Voltage Ride Through ...... 10 3 STUDY CASE PREPARATION AND ASSUMPTIONS ...... 13 3.1 Power-flow preparation ...... 13 3.2 Study scenarios ...... 14 3.3 Study generation assumptions ...... 15 3.4 Other study assumptions ...... 16 4 LIGHT LOAD HIGH VOLTAGE MANAGEMENT ...... 18 4.1 Background - Lightly loaded lines generate MVAr in the system ...... 18 4.2 Study methodology ...... 19 4.3 Study results...... 20 5 VOLTAGE RIDE THROUGH CAPABILITY OF SOLAR PV INVERTERS ...... 34 5.1 Introduction ...... 34 5.2 Definitions ...... 34 5.3 Impact on fault levels and step-voltage management ...... 36 5.4 Effect of transmission faults on inverter ride through capability ...... 42 6 THE EFFECT ON VOLTAGE STABILITY ...... 51 6.1 Background ...... 51 6.2 Study methodology ...... 51 6.3 Study results...... 52 7 KEY FINDINGS AND CONCLUSIONS ...... 61 7.1 Voltage management during light load ...... 61 7.2 Effect on fault levels ...... 62 7.3 PV generation voltage ride through capability ...... 62 7.4 Effect on voltage stability ...... 63 7.5 Study limitations ...... 63 8 RECOMMENDATIONS ...... 65 8.1 Voltage management strategy ...... 65 8.2 Inverter standard ...... 65 8.3 Collaboration with distribution network operators ...... 65 8.4 Long term planning ...... 66 A1 POWER-FLOW SUMMARY BY GRID ZONE ...... 67

A2 FAULT LEVEL AND VOLTAGE STEP INFORMATION ...... 70 A2.1 System strength and equivalent system impedance ...... 70 A2.2 Short-circuit current and equivalent system impedance ...... 70 A2.3 Technical background – fault level analysis ...... 71 A2.4 Technical background – voltage step analysis ...... 72 A2.5 Generator dispatch status table ...... 72 A2.6 Fault current change maps ...... 73 A3 INVERTER MODELS ...... 78 A3.1 Active power/frequency control ...... 79 A3.2 Reactive power/voltage control ...... 81 A3.3 Voltage/Frequency ride through ...... 85 A3.4 Reconnect characteristics ...... 87 A3.5 Inverter type distribution ...... 87 A4 VOLTAGE STABILITY STUDY RESULTS...... 88 A4.1 Voltage stability explained ...... 88 A4.2 Interface MW transfer and voltage stability load limit results tabulation ...... 94 A4.3 Contingency set used for voltage stability studies ...... 96 A4.4 Effect of PV generation on voltage stability for summer scenario ...... 97 A4.5 Effect of PV generation on transmission line loading for the summer scenario ...... 99 A4.6 PV curves under pre-contingent conditions for winter and summer power-flow scenarios . 100 A4.7 QV curves of winter and summer power-flow scenarios ...... 109 A5 EMERGING ENERGY PROGRAMME: PLAN AND OUTCOME STRATEGY ...... 111 A5.1 Emerging Energy Technologies – Outcome Strategy Map ...... 112 GLOSSARY OF TERMS AND ACRONYMS ...... 113 BIBLIOGRAPHY ...... 118

Table of Figures

Figure 1: North Island no-trip zone during 110 kV or 220 kV faults [3] ...... 10 Figure 2: South Island no-trip zone during 110 kV or 220 kV faults. [3] ...... 11 Figure 3: Inverter LVRT/Passive Anti-Islanding AS/NZS 4777.2 requirements [4] ...... 12 Figure 4: Flow diagram for creating power-flow files from GXP PV generation profiles ...... 14 Figure 5: winter Tuesday 28/07/2015 sunny day scenarios ...... 15 Figure 6: summer Sunday 10/01/2016 sunny day scenarios ...... 15 Figure 7: Transmission line reactive power production ...... 19 Figure 8: Flow chart describing study methodology of light load high voltage management ...... 20 Figure 9: Summer 3350 MW (12:00) base case and N-1 voltages - 1 PAK-WKM circuit out ...... 21 Figure 10: Summer 3000 MW (16:00) base case and N-1 voltages ...... 22 Figure 11: Summer 3000 MW (16:00) base case and N-1 voltages – PAK-WKM-1 out and ARI-G8 in...... 22 Figure 12: Winter 3150 MW (13:00) base case and N-1 voltages ...... 23 Figure 13: Summer 3350 MW (12:00) South Island base case and N-1 voltages ...... 24 Figure 14: Winter 3150 MW (13:00) South Island base case and N-1 voltages ...... 24 Figure 15: Upper North Island 220 kV bus voltages summer 3000 MW (16:00) scenario ...... 26 Figure 16 Upper North Island 220 kV bus voltages summer 3000 MW (16:00) scenario – ALB SVC contingency ...... 26 Figure 17: Central North Island 220 kV bus voltages summer 3000 MW (16:00) scenario ...... 28 Figure 18: Central North Island 220 kV bus voltages summer 3000 MW (16:00) scenario – TMN-TKH-1 contingency ...... 28 Figure 19: Central/Lower North Island 110 kV bus voltages summer 3000 MW (16:00) scenario ...... 30 Figure 20: Central/Lower North Island 110 kV bus voltages summer 3000 MW (16:00) scenario – MTR-OKN- 1 contingency ...... 30 Figure 21: Winter 3150 MW (13:00) power-flow upper South Island voltage heat map ...... 31 Figure 22: Winter 3150 MW (13:00) power-flow upper South Island voltage heat map – KIK STC contingency ...... 31 Figure 23: Changes in regular steady-state voltage steps reflect changes in system impedance and system strength...... 35 Figure 24: Change in fault currents from 0 MW to 3150 MW – 220 kV network ...... 39 Figure 25: Zoom on Grid Zone 1-4. Change in fault currents from 0 MW to 3150 MW – 220 kV network .... 39 Figure 26: Change in fault currents from 0 MW to 3150 MW – 110 kV network ...... 39 Figure 27: Zoom on Grid Zone 1-4. Change in fault currents from 0 MW to 3150 MW – 110 kV network .... 39 Figure 28: Inverter Voltage Ride Through Characteristics ...... 43 Figure 29: winter 3150 MW OTA 110 kV fault simulation – Bus voltage and Inverter LVRT characteristics .. 44 Figure 30: Bus voltage during an Otahuhu 110 kV line, three phase fault – winter scenarios ...... 45 Figure 31: solar PV Inverter trip MW for an Otahuhu 110 kV line fault – winter ...... 46 Figure 32: solar PV Inverter trip MW for an Otahuhu 110 kV line fault – summer...... 46 Figure 33: Bus voltage during an Islington 66 kV line, three phase fault – winter scenarios ...... 47 Figure 34: solar PV Inverter trip MW for Islington 66 kV line fault – winter ...... 48 Figure 35: solar PV Inverter trip MW for ISL66 line fault – summer Sunday 10/01/2016 ...... 48 Figure 36: Murchison PV bus voltage increase during Kikiwa T2 contingency ...... 49 Figure 37: Values of source and sink at the transfer limit in UNI region with a rise in PV generation over the day – winter scenario ...... 53 Figure 38: UNI region PV curves for selected 220 kV circuits - winter 1300 base case pre- and post- contingency of a HLY-TWH1 220 kV circuit ...... 53 Figure 39: UNI equivalent line charging and shunt MVAr reserve thought the day - winter scenario ...... 54 Figure 40: Values of source and sink at the transfer limit in USI region with a rise in PV generation over the day – winter scenario ...... 55

Figure 41: USI region PV curves for selected 220 kV circuits - winter 1300 base case pre- and post- contingency of a ISL-LIV 220 kV circuit ...... 55 Figure 42: USI equivalent line charging and shunt MVAr reserve thought the day - winter scenario ...... 56 Figure 43: Effect of solar PV on line loadings in the UNI region for a winter Scenario ...... 57 Figure 44: Effect of solar PV on line loadings in the USI region for a winter Scenario ...... 58 Figure 45: UNI region QV curves for selected 220 kV circuits - winter 1300 base case pre- and post- contingency of a HLY-TWH1 220 kV circuit ...... 59 Figure 46: USI region QV curves for selected 220 kV circuits - winter 1300 base case pre- and post- contingency of ISL_LIV 220 kV circuit ...... 59 Figure 47: The equivalent impedance includes the transmission system impedance, and any other impedances such as shunt capacitors and internal reactances of all online generating units ...... 70 Figure 48: Change in fault currents from PV 0 MW to 750 MW – 220 kV network ...... 74 Figure 49: Change in fault currents from PV 0 MW to 3100 MW – 220 kV network ...... 74 Figure 50: Zoom on Grid Zone 1-4. Change in fault currents from PV 0 MW to 750 MW – 220 kV network 75 Figure 51: Zoom on Grid Zone 1-4. Change in fault currents from PV 0 MW to 2650 MW – 220 kV network75 Figure 52: Zoom on Grid Zone 1-4. Change in fault currents from PV 0 MW to 2050 MW – 220 kV network75 Figure 53: Zoom on Grid Zone 1-4. Change in fault currents from PV 0 MW to 3100 MW – 220 kV network75 Figure 54: Change in fault currents from PV 0 MW to 750 MW – 110 kV network ...... 76 Figure 55: Change in fault currents from PV 0 MW to 3100 MW – 110 kV network ...... 76 Figure 56: Zoom on Grid Zone 1-4. Change in fault currents from PV 0 MW to 750 MW – 110 kV network 77 Figure 57: Zoom on Grid Zone 1-4. Change in fault currents from PV 0 MW to 2650 MW – 110 kV network ...... 77 Figure 58: Zoom on Grid Zone 1-4. Change in fault currents from PV 0 MW to 2050 MW – 110 kV network77 Figure 59: Zoom on Grid Zone 1-4. Change in fault currents from PV 0 MW to 3100 MW – 110 kV network77 Figure 60: solar PV Inverter Over-Frequency Response ...... 79 Figure 61: Frequency Control component of Inverter C Dynamic Model ...... 80 Figure 62: solar PV Inverter Volt-Var Response to voltage step ...... 81 Figure 63: solar PV Inverter Constant Powerfactor Response to over-frequency event ...... 82 Figure 64: Volt-Var component of Inverter Dynamic Model ...... 83 Figure 65: Constant Power Factor component of Inverter Dynamic Model ...... 84 Figure 66: Voltage and Frequency trip and reconnect component of Inverter C Dynamic Model ...... 86 Figure 67: Classification of Power System Stability [5] ...... 89 Figure 68: PV Curve [6] ...... 90 Figure 69: QV Curve [7] ...... 90 Figure 70: Two-Bus representation of Power System ...... 93 Figure 71: VSAT's iterative technique for solving for voltage stability limits ...... 94 Figure 72: UNI region interface transfer flow and load limit changes with a rise in PV generation over the day – summer scenario ...... 97 Figure 73: USI region interface transfer flow and load limit changes with a rise in PV generation over the day – summer scenario ...... 97 Figure 74: UNI equivalent line charging and shunt MVAr reserve thought the day - summer scenario ...... 98 Figure 75: USI equivalent line charging and shunt MVAr reserve thought the day - summer scenario ...... 98 Figure 76: Effect of solar PV on line loadings in UNI region for a summer Scenario ...... 99 Figure 77: Effect of solar PV on line loadings in USI region for a summer Scenario ...... 99 Figure 78: PV curve of selected 220 kV buses in UNI region for pre-contingency winter 07:00 scenario .... 100 Figure 79: PV curve of selected 220 kV buses in UNI region for pre-contingency winter 08:00 scenario .... 100 Figure 80: PV curve of selected 220 kV buses in UNI region for pre-contingency winter 11:00 scenario .... 101 Figure 81: PV curve of selected 220 kV buses in UNI region for pre-contingency winter 12:00 scenario .... 101 Figure 82: PV curve of selected 220 kV buses in UNI region for pre-contingency winter 13:00 scenario .... 101 Figure 83: PV curve of selected 220 kV buses in UNI region for pre-contingency winter 14:00 scenario .... 102 Figure 84: PV curve of selected 220 kV buses in UNI region for pre-contingency winter 16:00 scenario .... 102

Figure 85: PV curve of selected 220 kV buses in UNI region for pre-contingency winter 17:00 scenario .... 102 Figure 86: PV curve of selected 220 kV buses in UNI region for pre-contingency winter 18:00 scenario .... 103 Figure 87: PV curve of selected 220 kV buses in USI region for pre-contingency winter 07:00 scenario .... 103 Figure 88: PV curve of selected 220 kV buses in USI region for pre-contingency winter 08:00 scenario .... 103 Figure 89: PV curve of selected 220 kV buses in USI region for pre-contingency winter 11:00 scenario .... 104 Figure 90: PV curve of selected 220 kV buses in USI region for pre-contingency winter 12:00 scenario .... 104 Figure 91: PV curve of selected 220 kV buses in USI region for pre-contingency winter 13:00 scenario .... 104 Figure 92: PV curve of selected 220 kV buses in USI region for pre-contingency winter 14:00 scenario .... 105 Figure 93: PV curve of selected 220 kV buses in USI region for pre-contingency winter 16:00 scenario .... 105 Figure 94: PV curve of selected 220 kV buses in USI region for pre-contingency winter 17:00 scenario .... 105 Figure 95: PV curve of selected 220 kV buses in USI region for pre-contingency winter 18:00 scenario .... 106 Figure 96: PV curve of selected 220 kV buses in UNI region for pre-contingency summer 08:00 scenario 106 Figure 97: PV curve of selected 220 kV buses in UNI region for pre-contingency summer 10:00 scenario 106 Figure 98: PV curve of selected 220 kV buses in UNI region for pre-contingency summer 11:00 scenario 107 Figure 99: PV curve of selected 220 kV buses in USI region for pre-contingency summer 08:00 scenario . 107 Figure 100: PV curve of selected 220 kV buses in USI region for pre-contingency summer 10:00 scenario 107 Figure 101: PV curve of selected 220 kV buses in USI region for pre-contingency summer 11:00 scenario 108 Figure 102: QV curves of 220 kV buses in the UNI region under pre-contingent conditions – winter 13:00 scenario ...... 109 Figure 103: QV curves of 220 kV buses in the UNI region HLY-TWH 1 contingency – winter 13:00 scenario ...... 109 Figure 104: QV curves of 220 kV buses in the USI region under pre-contingent conditions – winter 13:00 scenario ...... 110 Figure 105: QV curves of 220 kV buses in the UNI region ISL-LIV contingency – winter 13:00 scenario .... 110

EXECUTIVE SUMMARY

Transpower has initiated a programme of work to investigate the impacts on the power system from an anticipated increase in distributed, non-dispatchable and renewable generation, and from other emerging technologies in New Zealand. The aim of Transpower’s Emerging Energy Programme is to identify potential compromise to Transpower’s ability to meet the system operator Principal Performance Obligations (PPOs) with the introduction of new generation technologies. The alternative would involve a revision of the PPOs to accommodate these emerging technologies. The first part of the programme features the PV Generation Investigation Project, which studies the effect of PV generation technology on four areas of the power system: generation dispatch, frequency management, transmission voltage management and transient stability. Study reports have been produced for each of these areas, with this report covering the study into voltage management under high penetration levels of solar PV in the power system. All the project studies used a scenario of 4 GW [1] of solar PV capacity installed, as discussed in the generation dispatch study (refer to Effect of Solar PV on Generation Dispatch in New Zealand). This study into voltage management with increasing levels of PV generation concludes the New Zealand power system can operate stably with PV generation increased to the level of 4 GW installed capacity. This assumes the current generation mix remains in-place; e.g, to meet evening maximum demand. This equates to about 3350 MW of PV generation embedded in the distribution network. Stable operation with this level of PV penetration will however require operational measures, such as switching out transmission circuits, to manage over-voltages. Taking into account study limitations and the inherent uncertainty in PV generation operating behaviour, the current power system should have adequate capacity and capability to operate the power system securely and reliably with PV generation level at around 2000 MW. At this PV generation level, no additional operational measures such as switching out transmission circuits are needed to manage over-voltages during maximum PV generation condition. However, it is advisable to begin considering if the current regulatory and operation framework is fit for purpose to operate a power system with a large quantity of embedded distribution generation. A large quantity of embedded distribution generation, if not visible to the system operator, may pose a risk to stable system operation. Learning about this new technology and adapting operation tools and processes to meet the challenge of operating the power system with high PV generation is a continuous effort.

When PV generation grows above 1000 MW, the transmission system dynamic reactive power regulation capability may start to deteriorate. This will be partly due to the displacement of grid connected synchronous generators and the reactive power generated by the lightly load transmission circuits. This effect could be exacerbated with a distribution feeder with high PV penetration, in which excess reactive power would flow into the transmission system, raising the transmission system voltage. Consequently, it is important Transpower system operator and distribution companies work together to provide visibility of those distribution feeders with high PV generation. In the future, the power system may have a very different load demand profile compared to today. The minimum demand during midday could be 50% or lower than the maximum demand depending on the amount of PV generation on the system. The present midday minimum demand seldom goes below 20% of the maximum demand. Consequently, the future power system must have adequate flexibility to be able to operate securely and reliably for all the system conditions. This applies to real time operation, which has to be agile enough to manage the system conditions within the statutory limits for both maximum and minimum demand. The study included several conservative assumptions (see section 3). The accuracy of the studies could be improved if more detailed information was obtained, such as high speed solar irradiance data from more weather stations, extra inverter test data (to develop more accurate computer models) and distribution network models. However, we believe additional accuracy is unlikely to materially alter the conclusions of this study. Collaboration across the electricity industry to study the possibilities arising from using solar inverter features to support secure and stable grid operation could be valuable for the future operation of both distribution and the national power system. The fast and flexible control provided by appropriately specified solar inverters can enhance the flexibility and resilience of the future grid. The learnings gained in these studies will be useful in steering the future of the system operator service, electricity market design, industry regulations, policies and procedures for a period of increasingly decentralised supply and responsive consumer technologies. Ultimately, this understanding will facilitate an evolving power system which can continue to meet the changing needs of New Zealanders.

1 INTRODUCTION 1.1 Programme Overview Transpower's Emerging Energy Programme investigates the potential impacts on the power system resulting from an anticipated increase in distributed, non-dispatchable, renewable generation and other emerging technologies in New Zealand. The programme outlines the strategy Transpower has adopted to develop its capability and business processes to enable a successful integration of such technologies in the New Zealand power system. See Appendix A6 for a scope of work flowchart that summarises Transpower's Emerging Energy Programme.

1.1.1 The growth of distributed, non-dispatchable renewable generation Distributed, non-dispatchable electricity generation, primarily PV generation, has grown rapidly in most regions around the world in recent years. The change in technology costs, consumer preferences, policies and environmental concerns, leads to this trend of growth [1]. PV generation uptake is still relatively low in New Zealand. However, the rate of growth is expected to increase for the foreseeable future, with PV generation projected to become a significant part of New Zealand's electricity supply mix. Other emerging technologies (such as energy storage devices, Home Energy Management Systems (HEMS), Electric Vehicles (EVs) and smart appliances) will also play a role in shaping the future of the New Zealand power system. New business models for energy trading and distributed generation ownership will facilitate consumer choice and change the way we produce and use electricity. Though the cumulative effect of these developments is highly interdependent and difficult to predict, the electricity industry will need to be proactive in meeting changing consumer expectations and a shifting market environment, to avoid significant business disruptions.

1.1.2 Assessing New Zealand's ability to adapt to new technologies The New Zealand power system has some unique features not the least of which is being an islanded system with a high proportion of electricity generated from hydro-power backed by storage. A 2008 study of the system's ability to accommodate wind generation indicated that hydro generation afforded a high degree of flexibility to accommodate intermittent generation. Transpower is assessing the possible future impacts of intermittent generation technologies on the power system and the policies it may need to adopt to continue to meet the PPOs in its role as system operator. These assessments will also provide useful context for the future development of the Electricity Industry Participation Code (the Code), including the PPOs.

1.1.3 The challenges due to the variability of PV Generation Electricity produced from solar irradiance depends on the position of the sun, which is predictable though variable. With consistently clear or overcast weather, PV generation output can be relatively steady; with output increasing in the early morning and

decreasing during the late afternoon. However, PV generation output can be highly variable with changeable and fast moving cloud. The variability and intermittent effects of PV generation can cause operational issues for grid management. The increase in inverter-based generation in the power system (replacing conventional synchronous generators) can alter the dynamic behaviour of the power system. Inverters are highly programmable making their behaviour less predictable. Furthermore, PV generation will be more distributed compared to the present centralised generation topology. This form of distributed generation presents challenges in studying the dynamic behaviour and real-time operation of the power system. However, the studies are needed in order to understand the effect of PV generation variability and intermittency on the power system, and in forecasting the likely impact on the reliability of the ancillary services.

1.2 The PV Generation Investigation Project Transpower's PV Generation Investigation Project is part of the wider Emerging Energy Programme to ensure a smooth integration of these new technologies in New Zealand. The PV Generation Investigation Project provides studies into PV generation technologies and can be broadly separated into four main areas: generation dispatch, frequency management, transmission voltage management and transient stability.

1.3 The New Zealand power system

1.3.1 Overview The New Zealand power system has several features which have the potential to impact the integration of distributed, non-dispatchable generation. The major factor is that ours is an isolated system with a high proportion of electricity generated from renewable sources which can vary in availability; namely hydro and wind generation. It is necessary to understand the impact to New Zealand's security of supply due to additional variable energy sources that are not highly correlated to either hydrology or wind resources. A significant increase in the share of PV generation in the generation mix may require changes to the existing transmission network equipment, operational processes, code and industry standards to: • Secure adequate responsive generation (and possibly energy storage) capacity to manage the variable and intermittent nature of non-dispatchable PV generation. • Introduce new equipment and operational measures to ensure adequate grid stability and control. • Include distributed PV generation forecasting into scheduling processes. • Ensure prices reflect economic costs. In reading the study reports produced for the PV Generation Investigation Project it is assumed the reader is familiar with the New Zealand power system, including the following key features: • There is good generation mix with approximately 80% of electricity supply from variable renewable sources. • There is existing thermal plant. • There have been recent thermal plant retirements. • There is existing wind penetration. • It is a two island system; it is relatively small, with low inertia at times and large generating units present susceptibility to frequency disturbances. • There is a mix of generation characteristics - fast ramping hydro, slower ramping thermal, constant geothermal, variable wind, etc. • Transpower holds a classification of power system risks. • Voltage management methods employed to manage transmission voltage.

1.3.2 PV generation in New Zealand PV generation uptake in New Zealand has been relatively low. As of December 2017, New Zealand's installed PV generation capacity has grown to a total of 62 MW, with generation from residential, commercial and industrial sites [1]. This growth places total installed PV generation capacity at a level similar to the smaller, run-of-river hydro stations in New

Zealand. However, at typical New Zealand solar capacity factors, this installed generation supplies only around 0.1% of total national energy consumption. This level of PV generation capacity has not compromised our ability to operate the power system securely and economically, with the existing tools and policies. However, the rate of growth is rapid, with a doubling time for installed PV generation capacity of approximately 18 months. PV generation installations are expected to continue to grow, as falling costs and an expanding market drive an increasing pace of PV generation uptake. Integration of high levels of PV generation into the power system will impact the frequency response to system imbalance, for the reasons outlined below: • It is distributed and non-dispatchable, and therefore offsets load behind the GXP, with limited system operator visibility. • It is highly stochastic, with rapid changes in output possible, depending on the relevant temporal and spatial scales, type of weather, season and level of uptake. • The normal PV generation profile is negatively correlated with demand at times of maximum peak PV generation during mid-day, resulting in low system inertia that is susceptible to frequency disturbance. • Inverter-based PV generation exhibits different frequency behaviour when subjected to system imbalance compared to conventional synchronous generation.

1.4 Impacts on voltage management Power system reliability depends on an ability to ride through a defined contingent event and remain in a stable operating state. The power system is expected to provide continuous electricity supply with voltage and frequency within the statutory ranges. Roof-top PV generation represents another form of distributed and non-dispatchable generation. An increase in PV generation will displace grid connected synchronous generation thereby changing the distribution of generation mix and alter the pattern of power flowing through the transmission system. This will result in significant changes to the way Transpower plans and operates the power system. Historically, synchronous generators connected at the transmission level have provided ancillary (reliability) services required to reliably operate the power system. Synchronous generation provides fault current and static and dynamic reactive power support to manage transmission voltage. These ancillary/reliability services are an integral part of a reliable power system operation and help maintain transmission voltage within a stable limit, enabling reliable transportation of electrical power across the transmission system. Displacement of synchronous generation reduces or, ultimately, removes important ancillary services that help manage transmission voltage. In addition, PV generation serving the local demand reduces the need to transport electrical power across the transmission system, resulting in lower loading of transmission circuits. The consequence

of this is a voltage rise, requiring the remaining reactive power support devices to manage transmission voltages. For a high PV penetration scenario, the deficiency in reactive power regulating devices across the transmission system, coupled with high voltages, may require extreme measures to manage transmission voltages. These might include switching out transmission circuits and curtailment of PV generation. This study investigates the system capability to manage voltage under high PV generation where system voltage is high and there are limited reactive power regulating devices. There are four major effects on voltage management because of the reduction of the above mentioned elementary ancillary services: • Reduction in short circuit current contributed by synchronous generation in the transmission system may cause voltages to be more susceptible to system disturbances, such as circuit or capacitor bank switching. • Reduction in online synchronous generation would reduce the ability of the system to regulate post event voltage in the transmission system, especially during the midday when PV generation is at its maximum. • The effect on voltage stability with high PV generation. • An increase in PV generation penetration could compromise ancillary services, affecting Transpower's ability to manage transmission voltage to meet its PPOs. These changes in system dynamics will inevitably change the way the power system is planned, assets are utilised, and the overall system is operated. This study represents Transpower's work to gain an understanding of these changing characteristics in order to be able to offer reliable operation in the future.

2 EXISTING VOLTAGE MANAGEMENT PRACTICES

New Zealand is rich in natural energy resources such as hydro and geothermal. However, a key feature of the New Zealand power system is that the main load centres are located some distance from areas of significant generation. The New Zealand power system encompasses two islands, connected by an HVDC link. The North Island power system serves an island maximum demand of 4500 MW, with power generated from a mixture of fuel sources, namely: hydro, wind, geothermal, gas and coal. The South Island serves a maximum demand of 2200 MW, with generation from hydro only. Most of the time, excess hydro generation from the South Island is exported through the HVDC link to meet demand in the North Island. Most North Island generation installed capacity is located in the central North Island and Stratford regions, with additional generation from the Huntly thermal power station located near Auckland and the large wind farms in the Wellington region. Most generation supplies demand in the three major load centres; Auckland, Wellington and Christchurch. This makes up approximately 30-35% of total New Zealand maximum demand. The largest single user of electricity in the country is New Zealand Aluminium’s Tiwai Point smelter which consumes about 600 MW of electric power. See Appendix A1 for the Grid Zone generation and demand data. Since the major load centres are located some distance from the areas of significant generation, an extensive transmission system is required. This poses challenges for the system operator to manage transmission voltage within the statutory limits prescribed in the Code. Managing grid voltage issues is a fundamental component of power system operation. This section discusses the present voltage management practices relevant to the issues assessed in this study.

2.1 System Operation Principle Performance Obligation (PPO) in voltage management Subsection 8.2 of the Code stipulates that the system operator must maintain pre- and post-contingent event voltage within the Asset Owner Performance Obligations (AOPO) voltage range, that is: • +/- 10% for 220 and 110 kV • +/- 5% for 66 and 50 kV In addition, the Code stipulates that generation units shall remain connected to support the system voltage when it is within statutory limits.

2.2 Voltage management The New Zealand transmission system's grid backbone is formed by high capacity, high voltage transmission lines and cables. The AC transmission systems of the two islands are linked together by a 1200 MW HVDC Inter-island link. The HVDC link allows transfer of generation in both directions providing greater operational flexibility to optimise generation cost and improve resilience to system disturbance. This long high voltage transmission system poses a significant challenge for the system operator to manage system voltage within the Code limits for all operating conditions. The transmission system behaves like an inductor, absorbing reactive power when the network delivers high electrical power to load centres. Various operational measures have been established for managing low voltage and voltage stability to ensure secure system operation. When there is a trough in load demand the low levels of power transported through the transmission system make the network capacitive. This lightly loaded network produces reactive power, which inevitably increases system voltage. To manage this effect, the system operator employs measures to control system voltage such as: • Utilisation of SVC/STATCOM • Switching off capacitor banks • Switching out lightly loaded transmission circuits • Dispatch generator to absorb reactive power In addition, the system operator is required to manage post-event system voltage to maintain grid operability and stability. Transpower has identified potential credible events in power system operation and categorized them into two different risk classes, namely Contingent Event (CE) and Extended Contingent Event (ECE) (described below). Voltage risk is managed based on the appropriate risk class and the application of suitable mitigation measures to avoid power system events from causing voltage to exceed the statutory limits.

Contingent Event (CE) Contingent Event or CE refers to a power system event involved in the disconnection of a single power system component such as a transmission circuit, an HVDC link pole, a single generating unit, a single ancillary service injection point and a load block. A CE is an event in which the impact, probability of occurrence, and estimated cost and benefits of mitigation are considered justification to apply mitigation measures pre-event, to avoid post-event frequency exceeding the limits. Sufficient asset capacity and reserve is dispatched to provide adequate redundancy to maintain the level of quality prescribed in the Code and avoid post-event unplanned demand shedding.

Extended Contingent Event (ECE) Extended Contingent Event or ECE refers to a power system event involving disconnection of multiple power system components by a single event or simultaneous disconnection of multiple components. ECE events are the loss of the HVDC link bipole, loss of a 220 kV or 110 kV bus and loss of a 220 kV interconnecting transformer. An ECE is not considered to justify the control required to avoid total demand shedding. Hence, post-event demand loss is regarded as an acceptable system management response.

2.2.2 Management of under-voltage The system operator manages the system voltage above the lower statutory voltage limit to avoid damaging equipment connected to the power system and to avoid mal-operation of the protection system. Generally, under-voltage conditions arise when system load is high and reactive power reserve is scarce. Heavily loaded transmission circuits absorb reactive power, causing lower voltage at the receiving bus. The first option to manage under-voltage is to schedule additional reactive power at the receiving bus to maintain voltage within the statutory limit. If a local reactive power source is not available, more distant reactive power sources will be utilised to increase the overall area voltage profile, thus helping to maintain the voltage at the receiving bus at the statutory limit. However, the latter option is less effective and will increase system losses. The system operator endeavours always to maintain system voltage above the statutory limit during normal operating conditions and following a contingency. Discrete shunt devices such as capacitor banks and reactors are used to maintain steady state voltage, whereas generation units, SVCs and STATCOMs are used to provide both steady state and dynamic voltage control. If the system operator exhausts all options to manage system voltage above the statutory limit, other more extreme measures such as grid reconfiguration or load management will be deployed.

2.2.3 Management of over-voltage High voltage increases the risk of insulator failure, causes incorrect operation of electrical equipment and can be a danger to human life. The system operator manages high voltage conditions by switching off excess capacitor banks in the system and using generation and other dynamic reactive power regulating devices such as SVCs and STACOMs to absorb excess reactive power. Dynamic reactive power regulating devices are used to provide steady state regulation as well as managing post-event voltage.1 To enable post-event regulation, the devices are operated at a predetermined level to offer fast reactive power regulating reserve. This provides automatic post-event regulation in order to maintain system voltages below the limit. The current operation policy requires that the dynamic reactive power regulating devices should not import more than 25% of its rated capability. If all options fail to maintain the dynamic reactive power reserve, the system operator will remove one or more highly capacitive (lightly loaded) circuits from service. This reduces the overall reactive power available in the power system. As other connected circuits are lightly loaded, the measure should not result in reduced system security. The system operator has operational procedures in place to manage voltages during low load. These include: • Switching capacitors/reactors • Lowering the voltage set points of generation to absorb reactive power • Lowering the voltage set points on dynamic reactive plant (Synchronous condensers, SVC's and STATCOM's) • Switching out transmission lines to reduce reactive power production in the power system. The following circuits are identified as effective at reducing voltages for specific regions2:

o Upper North Island:

- Pakuranga-Whakamaru 1 and 2 220 kV circuits

- Pakuranga-Penrose-3 220 kV circuit

o Central North Island:

- Huntly Stratford-1 220 kV circuit

- Brunswick-Stratford 1, 2 or 3 220 kV circuit

o Upper South Island:

- Islington-Kikiwa-1 220 kV circuit

- Islington-Livingston-1 220 kV circuit . Ashburton-Islington-1 220 kV circuit

1 The term “voltage regulation” is used in this report to refer to reactive power support to reduce system voltages. 2 PR-DP-235_Manage Grid and Supply Voltage – Transpower, system operator

2.2.4 Managing voltage stability It is important to maintain voltage stability to ensure that: • Voltage of the power system is stable under normal system conditions • Voltages will not become unstable after a fault or disturbance, resulting in a progressive and uncontrollable decline in voltage The system operator runs online voltage stability assessment software. This is based on static analysis for voltage security assessment and transfer limit computations subject to voltage security criteria and contingencies. The voltage stability assessment is run every trading period to determine the transfer limit for predefined transmission corridors. A 5% stability margin is applied to provide an operational safety margin.

2.3 Voltage Ride Through The Code requires the grid connected generators to remain connected following a fault in order to support the system voltage. If the generators do not ride through a fault this can pose a secondary risk that impedes system recovery. Subsection 8.25A of the Code specifies the voltage ride through requirements to which generation should adhere: • Faults in the North Island (Figure 1) • Faults in the South Island (Figure 3)+ • High Voltage Direct Current (HVDC) link trip

Figure 1: North Island no-trip zone during 110 kV or 220 kV faults [3]

Figure 2: South Island no-trip zone during 110 kV or 220 kV faults. [3] The Standard for Power Inverters, AS/NZS 4777.2:2015 [4] addresses the requirements for solar PV inverters in New Zealand. The standard sets out protective functions for anti-islanding, and states a requirement that inverters must remain connected for voltage variations shorter than the specified trip delay time. Figure 3 below shows the low voltage ride through (LVRT) requirements of inverters in ASNZ 4777.2, specified as passive anti-islanding set-point values. The standard specifies a trip delay time, and a maximum disconnection time. To be compliant, inverters must trip after the trip delay time and before maximum disconnection time.

1.20

1.00 No Trip Zone

0.80

0.60 ASNZ 4777.2 - Trip Delay Time

Voltage (pu) Voltage Trip Zone 0.40 ASNZ 4777.2 - Maximum Disconnection Time

0.20

0.00 0 0.5 1 1.5 2 2.5 Voltage Disturbance Duration (s)

Figure 3: Inverter LVRT/Passive Anti-Islanding AS/NZS 4777.2 requirements [4]

3 STUDY CASE PREPARATION AND ASSUMPTIONS

This section covers the study scenarios (and assumptions) considered in the analysis of high PV penetration and its effect on voltage management. The general policies used by the system operator to meet the PPOs for voltage events are classified by risk into the risk categories identified above.3 This study focuses on identifying the impacts of high PV penetration on transmission voltage management in two types of events, CE or ECE, using power system time domain simulation software. The mitigations currently used to ensure statutory limits and PPOs are maintained during voltage events on the system are outlined in section 2.

3.1 Power-flow preparation The cases used were developed during the work on the first report produced for the PV Generation Investigation Project - Effect of Solar PV on Generation Dispatch in New Zealand. Twelve sample study days were selected to provide representation of: • All four seasons • Examples of different types of daily profile (weekday, Saturday, Sunday) • A wide range of demand profiles • Different system conditions that can be expected on the power system A national PV installed value of 4 GW formed the GXP PV generation profiles used in the study presented in this report. The table below shows the study days selected to represent ideal PV generation output on cloudless, sunny days

Table 1: Selected study days for sunny-day PV generation investigation

Daily profile Summer Autumn Winter Spring Weekday 5 Jan 2016 14 Apr 2015 28 Jul 2015 27 Oct 2015 Saturday 9 Jan 2016 18 Apr 2015 1 Aug 2015 31 Oct 2015 Sunday 10 Jan 2016 19 Apr 2015 2 Aug 2015 1 Nov 2015

The generation dispatch schedule produced above together with the load and PV generation profiles for each generator and GXP on the power system were incorporated into power-flow study cases that were the focus of the analysis in this investigation. The PV generation profile at each GXP represents the aggregated MW output from the solar PV installed throughout the distribution network connected to that GXP. In the power-flow case, each ‘GXP aggregated PV generation’ is modelled as a single 11 kV

3 The policies used by the system operator are in the Policy Statement (https://www.ea.govt.nz/code-and-compliance/the- code/documents-incorporated-into-the-code-by-reference/)

generating unit, connected via a supply transformer with an assumed distribution equivalent (lumped) impedance of 10% on 100 MVA base. Figure 4 below illustrates the above process.

GXP PV generation profiles (W)

vSPD Generation, Load, Generator Offer PV Generation Powerflow files Stack Profiles

Load Profile

Figure 4: Flow diagram for creating power-flow files from GXP PV generation profiles

3.2 Study scenarios The scenarios studied in this analysis were developed during the work on the first report produced for the PV Generation Investigation Project - Effect of Solar PV on Generation Dispatch in New Zealand. Study scenarios were generated across the following sunny days: • Winter Tuesday 28/07/2015 • Summer Sunday 10/01/2016 Figure 5 and Figure 6 below show the generation, total load, net load and PV generation for the above winter and summer days. These scenarios were created based on an installed capacity of 4 GW, with PV generation reaching 3000 MW in winter and 3500 MW in summer. The scenarios illustrate how the system will change throughout the day. PV generation ramps up with increased solar irradiance, peaks at midday, then ramps back down as sunset approaches. However, the load change from sunrise to midday is reasonably flat. This allows an alternative view of the study scenarios. Instead of a single installed capacity ramping up over the course of a morning, every point in time during this period (e.g. snapshots 08:00, 08:20 through to 13:00) may be viewed as a different installed PV generation capacity applied to the midday load. This is because the system conditions at each point in time would be similar to the midday system conditions due to the flat load profile.

This correlation between ‘ramping PV generation’ scenarios and ‘installed capacity’ allows ‘ramping PV generation’ to be used to estimate the impact of varying levels on installed PV generation capacity on voltage management.

7000

6000

5000

4000

12:00 13:00 14:00 3000 11:00 10:30 15:00

Active Power (MW) 2000 09:35 16:00

1000 08:20 08:00 17:00 07:00 18:00 0 04:00 08:00 12:00 16:00 20:00 00:00 Time of Day Total Generation Net Load Total Load PV Generation Powerflow Cases

Figure 5: winter Tuesday 28/07/2015 sunny day scenarios

Figure 6: summer Sunday 10/01/2016 sunny day scenarios

3.3 Study generation assumptions Generation dispatch used in this study was produced using SPD and based on a ‘wet year’ scenario. A ‘dry year’ scenario was also analysed in the initial screening, but was not considered further. The risk quantity is expected to be similar for both dry year and wet year scenarios resulting in similar study conditions when assessing the voltage management capability of the New Zealand power system.

When using the ‘wet year’ scenario, generation inputs were modified to represent a conservative situation, as outlined below. • Hydro generation is used for base loading (dispatched first), leaving this technology less available to respond to marginal changes in demand. All existing hydro plants in both islands are considered available in the study, subject to transmission system capacity and outages. No plants were operating in Tail Water Depressed mode (TWD4). • Large thermal generators can incur significant start-up and shutdown costs and the amount of this type of generation made available in the cases was checked to avoid unrealistic outcomes5. This can impact on regional voltage management. • Resulting run times of generation were evaluated regarding likely participant behaviour, leading to the contingent thermal generation availability assumptions applied to all study days. • Instantaneous reserves (IR) were scheduled as per reserve requirements (summarised in the next section). • Generators were dispatched in both islands to ensure system voltage and stability can be maintained. • No other emerging technologies (such as energy storage systems) were considered in this study. • Only PV generation from rooftop installations was considered. The study did not consider grid connected large scale PV generation. • Only the power system at the date of assessment was considered; expected service dates for new or modified transmission augmentations were disregarded.

3.4 Other study assumptions Other study assumptions based on the power-flow during a high PV generation scenario were: • The HVDC remained in operation even at low transfer levels to offer frequency support for both islands. Some study cases had the HVDC operating in round power mode to offer full frequency sharing capability. • Generators, reactive power compensation devices, capacitor banks and reactors were scheduled to maintain transmission pre-contingent bus voltages below 1.05 pu. • Generators and dynamic compensation devices were operated as close to neutral as possible to provide maximum dynamic reactive power support.

4 Hydro generators can be dispatched in Tail Water Depressed mode (TWD) to dispatch reactive power only with no active power output. 5 Study cases considered closed-cycle gas turbines, open-cycle gas turbines, coal-fired units and diesel units offered in the market. The Otahuhu B, Southdown stations and Huntly Rankine units were not included in the study.

• PV generation produced no reactive power pre-event (generated at unity power factor), but will respond to voltage in the manner described by the inverter characteristics detailed in Appendix A3. This assumption was valid at the time of this study • The study assumed a sunny day PV generation scenario only. • System loads were modelled in power-flow as constant current for P and constant Impedance for Q.

4 LIGHT LOAD HIGH VOLTAGE MANAGEMENT

This section presents the analysis of high voltage management under high PV generation. The analysis considered steady state management of voltages, in a system with lightly loaded transmission circuits and low synchronous generation due to high PV generation.

4.1 Background - Lightly loaded lines generate MVAr in the system In an AC system, transmission circuits produce or absorb reactive power (Q), depending on how heavily loaded they are. A transmission line model can be simplified into 3 basic components: 1. Series resistance ( ) 2. Series inductive reactance ( ) 𝑅𝑅 3. Shunt capacitive reactance ( ) 𝑋𝑋𝑙𝑙 The shunt capacitive component of𝑋𝑋 𝑐𝑐the transmission circuit produces reactive power. The amount of reactive power produced depends on the voltage (V) at either end of the transmission circuit. The following relationship exists between reactive power, capacitance and voltage:

= 2 𝑉𝑉 𝑄𝑄𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝 The series resistive and inductive components𝑋𝑋 of𝑐𝑐 the transmission circuit relate to active and reactive power losses. The amount of reactive power absorbed depends on the current (I) flowing through the transmission circuit. The following relationship exists between reactive power, inductance and current: = 2 When a transmission circuit is lightly𝑄𝑄𝑎𝑎𝑎𝑎𝑎𝑎 𝑎𝑎𝑎𝑎loaded,𝑎𝑎𝑎𝑎𝑎𝑎 𝐼𝐼reactive𝑋𝑋𝑙𝑙 power produced by the circuit capacitance dominates reactive power absorbed by circuit inductance, resulting in net reactive power production from the transmission circuit. When a transmission circuit is heavily loaded, reactive power absorbed by circuit inductance dominates reactive power produced by the circuit capacitance. This results in net reactive power absorption from the transmission circuit. For all transmission circuits a loading exists such that reactive power absorption equals reactive power production, resulting in zero reactive power absorption. This loading is known as surge impedance loading (SIL) and is given by: | | = 2 𝑉𝑉 𝑆𝑆𝑆𝑆𝑆𝑆 𝑀𝑀𝑀𝑀 ��𝐿𝐿� � Where: 𝐶𝐶

• L = inductance (H) • C = capacitance (F)

Surge impedance is given by . 𝐿𝐿 Figure 7 below shows reactive� �power�𝐶𝐶� produced by an example transmission circuit against line loading. The transmission circuit produces reactive power when loaded below SIL and absorbs reactive power when loaded above SIL. High PV penetration supplies load at the demand location resulting in many transmission circuits across the power system being lightly loaded. The result is high reactive power generated from circuits, potentially resulting in high voltages in the power system.

Figure 7: Transmission line reactive power production

4.2 Study methodology Management of high voltages during high PV generation was carried out with power-flow analysis. Power-flow scenarios were extracted from the PV power-flow discussed in subsection 3.2. Under normal system operation, the pre-contingent transmission system voltages are kept at or below 1.03 pu when possible to allow headroom for post-contingency voltage management. Post contingent voltage above or close to 1.05 pu was flagged as a potential issue for system operation. Contingency analysis was performed to assess the impact of contingencies on bus voltages using power system steady-state power-flow analysis techniques. A single transmission circuit, generator, transformer or reactive power compensation device was removed to investigate the changes in the power system voltage profiles. The simplified flow diagram is depicted in Figure 8.

Steady State N-1 Analysis of High Analysis of High Votlages Voltages

High Voltage Powerflow files Management Conclusions

Line Charging Calculation

Figure 8: Flow chart describing study methodology of light load high voltage management

4.3 Study results Synchronous generators provide reactive power support to manage transmission system voltages. The displacement of synchronous generators from the transmission system depleted the voltage support reliability services impacting the ability to manage system voltages. In addition, the roof-top PV considered in this study would supply load at the demand location, resulting in less active power-flowing through transmission circuits from the remote generation sources. The lightly loaded transmission system generates more reactive power raising the system voltages. This section presents the results of the studies conducted to assess the effect of lightly loaded transmission circuits on transmission voltage management due to high PV generation. Appendix A1 provides a summary of the power-flow studied, summarising generation, load and PV generation by Grid Zone.

4.3.1 North Island The summer 3350 MW (12:00) scenario has 2580 MW of PV generation and 2780 MW load in the North Island. The high penetration of PV displaced synchronous generation connected to the transmission system leaving only 210 MW of synchronous generation remaining in the North Island. HVDC flow was minimal, implying that the 2780 MW North Island load was almost completely supplied from PV generation. The base power-flow was unstable until Pakuranga-Whakamaru-1 220 kV circuit was removed from service. All the capacitor banks were switched out of service and the remaining synchronous generators, SVC and STACOM were absorbing reactive power from the transmission system to manage high voltages. Figure 9 below shows the summer 3350 MW (12:00) study results. Pre-contingent voltages are shown in blue and post contingent voltages in red and orange. The contingency resulting in the post-contingent bus voltages is annotated on the plot. Voltages are high across the system, with the buses in North Island having pre-contingent voltage above 1.05 pu displayed in the graph. Taumarunui 220 kV bus (TMN 220) and Ohakune 110 kV bus (OKN110) showed a pre-contingent voltage of close to 1.08 pu. A contingency of Albany SVC resulted in power-flow instability. A loss of Wairau Rd 50 MVAr reactor and Mataroa-Ohakune 110 kV circuit caused a severe impact to voltages

in the upper and central North Island with Ohakune 110 kV bus experiencing the worst performance with a voltage rise of 3%. This operation condition is considered unacceptable for system operation. With 2580 MW of PV generation and only 210 MW of synchronous generation in the North Island, voltages would be difficult to control and the system would be exposed to large increases in voltage following line and reactive support contingencies.

1.11 MTR-OKN-1

1.1 WRD Reactor

1.09 WRD Reactor WRD Reactor WRD Reactor WRD Reactor TMN-TWH-1 1.08 WRD Reactor

1.07 Pre-Contingent TKU G1 Voltage WRD Reactor Post-Contingent 1.06 Voltage Post-Contingent Voltage

Bus Voltage (pu) 1.05 MDN STC5

1.04

1.03 ALB220 HLY220 MDN220 OTA220 TMN220 WKM220 WRD220 BPE220 OKN110 Bus

Figure 9: Summer 3350 MW (12:00) base case and N-1 voltages - 1 PAK-WKM circuit out The summer 3000 MW (16:00) scenario has 2280 MW of PV in the North Island. Voltages are lower than the 3350 MW scenario, but are still high across the system, with 220 kV buses in upper North Island and Taranaki region close to 1.05 pu. Ohakune 110 kV (OKN 110) bus shows a pre-contingent voltage of close to 1.04 pu. Post-contingent voltages range between 1.05 pu and 1.06 pu, which would require operational intervention to manage the system voltages down to a more acceptable level. The study result is depicted in Figure 10 below.

1.065 MTR-OKN-1

1.06 ALB SVC ALB SVC ALB SVC ALB SVC SFD G21 1.055

1.05

ALB SVC Pre-Contingent 1.045 Voltage

Post-Contingent Voltage 1.04 Bus Voltage (pu)

MDN STC5 1.035

1.03 ALB220 HLY220 OTA220 WKM220 WRD220 MDN220 OKN110 TMN220 Bus

Figure 10: Summer 3000 MW (16:00) base case and N-1 voltages

The summer 3000 MW (16:00) PV generation scenario was further analysed with the following measures to assist in the management of voltages: • Pakuranga-Whakamaru-1 220 kV circuit removed • Arapuni G8 constrained on for voltage management The operation measures brought the pre-contingency voltage to below 1.05 pu as shown in Figure 11 for the summer 3000 MW (16:00) scenario. Post-contingency voltages could be maintained to within 1.05 pu. Removal of a Bunnythorpe-Brunswick or Huntly-Stratford 220 kV circuit could be considered to improve the voltage at Stratford.

1.055

SFD G21 1.05 ALB SVC ALB SVC ALB SVC ALB SVC MTR-OKN-1

1.045 ALB SVC

1.04

Pre-Contingent 1.035 Voltage

Post-Contingent Voltage 1.03 Bus Voltage (pu) MDN STC5 1.025

1.02 ALB220 HLY220 OTA220 WKM220 WRD220 MDN220 OKN110 TMN220 Bus

Figure 11: Summer 3000 MW (16:00) base case and N-1 voltages – PAK-WKM-1 out and ARI-G8 in

Transmission system voltages can be managed adequately in winter as the generation by solar PV is lower in winter and the midday demand is higher than summer. The winter 3150 MW (13:00) scenario had 2450 MW of PV in the North Island. Figure 12 below shows voltages with 2450 MW of North Island PV generation in winter. No voltage issues were experienced in the upper North Island. Taumarunui 220 kV bus in Taranaki region experienced voltages above 1.05 pu with a loss of Taumarunui-Te Kowhai 220 kV circuit. High voltage in Tarakani was largely related to the displacement of synchronous generation in the area due to high PV generation.

1.06 TMN-TWH-1

TMN-TWH-1 1.05 TMN-TWH-1

1.04

1.03 Pre-Contingent Voltage ALB SVC ALB SVC 1.02 Post-Contingent Voltage Bus Voltage (pu)

1.01

1 ALB220 OTA220 TMN220 SFD220 BRK220 Bus

Figure 12: Winter 3150 MW (13:00) base case and N-1 voltages

4.3.2 South Island For the South Island, the summer 3350 MW (12:00) scenario had 730 MW of PV generation and the winter 3150 MW (13:00) scenario had 690 MW of PV generation. The study showed that the South Island power system can maintain transmission system voltages to an acceptable level for both summer and winter conditions. Figure 13 and Figure 14 depict the worst performing buses in South Island before and after a contingency. Kikiwa STACOM is one of only a few reactive power regulators in Grid Zone 9. Loss of Kikiwa STACOM would severely deprive the region of voltage regulation capability. The study showed that a loss of Kikiwa STATCOM, or Kikiwa T2 (the STATCOM is connected to the tertiary winding) could result in post-contingent voltages over 1.06 pu and approaching 1.07 pu on some of the buses in Grid Zone 9.

1.075 KIK T2 (STC)

1.065 KIK STC2

1.055 KIK T2 (STC)

1.045 KIK STC2

1.035 KIK T2 (STC) KIK STC2 1.025 Pre-Contingent Voltage 1.015 Post-Contingent Voltage Post-Contingent 1.005 ISLSVC9 Voltage Bus Voltage (pu) 0.995

0.985 ISLSVC9

0.975 WPT110 KIK220 KIK110 ISL220 ISL66 Bus

Figure 13: Summer 3350 MW (12:00) South Island base case and N-1 voltages

1.080 KIK T2 (STC)

1.070 KIK T2 (STC) KIK STC2 1.060 KIK STC2

1.050 KIK T2 (STC) KIK STC2 1.040 Pre-Contingent Voltage Post-Contingent 1.030 KIK T2 (STC) Voltage Post-Contingent Voltage

Bus Voltage (pu) 1.020 KIK T2 (STC) ISLSVC9 1.010

ISLSVC9 1.000 WPT110 KIK220 KIK110 ISL220 ISL66 Bus

Figure 14: Winter 3150 MW (13:00) South Island base case and N-1 voltages

4.3.3 Analysis - Areas with over-voltage issues and mitigation High PV generation manifests two significant effects on the power system that will affect the system operator’s ability to manage transmission system voltages. The effects are: • Displacing grid connected synchronous generation, reducing the ability to manage transmission system voltages. • Reducing the power flowing through the transmission circuit, thereby increasing transmission system voltages as explained in subsection 4.1.

In general, it is most effective to manage transmission system voltage locally. Hence, the study analysed voltage issues and mitigation measures in separate areas where voltage management issues were identified.

Upper North Island region The upper North Island region comprises Grid Zone 1 and Grid Zone 2. Grid Zone 2 contains the Auckland region, New Zealand’s main load centre. The upper North Island has little synchronous generation. Power is supplied to the region from the south, with major generation areas being Huntly thermal units and hydro, geothermal and thermal units in the central North Island. Power-flow through the 220 kV circuits from Whakamaru and Stratford to Auckland, via the Huntly and Hamilton areas, are critical during peak load periods. The high load and absence of synchronous generation required installation of capacitors, SVCs and STATCOMs to manage voltage in this region. Managing high voltages during light loads in the upper North Island is a present challenge for the system operator, typically seen during the night time trough (especially during summer). The distribution of PV produced during the work on the first report produced for the PV Generation Investigation Project - Effect of Solar PV on Generation Dispatch in New Zealand showed approximately 15% of PV uptake would occur in Grid Zone 1, with a further 23% in Grid Zone 2. This has the potential to displace a very large proportion of power supplied to upper North Island through transmission circuits and would require over-voltage management during a sunny day period. Our analysis concluded: • The winter 3150 MW (13:00, 2450 MW North Island PV) PV generation scenario showed that despite the high level of PV penetration in Grid Zone 1 and Grid Zone 2 voltages were manageable to acceptable limits with existing reactive plant in the region. No circuits would need to be removed for upper North Island voltage management. • The summer 3000 MW (16:00, 2280 MW North Island PV) scenario showed that during the midday period, with maximum PV generation, voltages would begin to breach acceptable limits. However, existing management practices of removing Pakuranga-Whakamaru 220 kV circuits would be an available method of reducing voltages in the region. The summer 3350 (12:00, 2580 MW North Island PV) scenario produced unacceptably high voltages for system operation. A contingency of Albany SVC resulted in power-flow instability. The power-flow was solvable only after removing a Pakuranga-Whakamaru 220 kV circuit from service. Displacement of synchronous generation due to PV generation resulted in too little North Island generation being available to regulate voltage under the high voltage conditions.

• Albany SVC provides the largest reactive power absorption in the upper North Island region. A contingency of Albany SVC resulted in high voltages in the area, increasing the Albany 220 kV bus voltage by about 1%. The heat maps in Figure 15 and Figure 16 show the 220 kV voltage profile in the upper North Island regions. Loss of the Albany SVC increased the transmission system voltage profile close to 1.05 pu across the upper North Island. Displacement of thermal generators in the upper North Island region reduces the voltage regulation capability in this region.

Figure 15: Upper North Island 220 kV bus voltages Figure 16 Upper North Island 220 kV bus voltages summer summer 3000 MW (16:00) scenario 3000 MW (16:00) scenario – ALB SVC contingency

Taranaki Region Taranaki region (Grid Zone 6) is located mid-way between Wellington and Auckland. The region is connected to the North Island 220 kV backbone at Bunnythorpe and Stratford 220 kV substations. The 220 kV network in this region provides a path for power to flow north from Wellington to Auckland, branching out from the centre of the North Island at Bunnythorpe, passing through Brunswick and Stratford and connecting into Huntly power station. The thermal generating units in this region form an integral part of the North

Island transmission system, managing voltage at the mid-point to allow stable transfer of electrical power to Auckland and the upper North Island. Managing high voltages in the Taranaki region is an existing challenge for the system operator, especially during light load when transmission circuit loading is low and thermal generation is not dispatched. Our analysis for this region concluded: • High PV generation reduced loading on transmission circuits and displaced generation in the area, reducing capability to absorb reactive power and control voltage in the region. • A contingency of Te Kowhai-Taumarunui 220 kV circuit placed the Taumarunui 220 kV bus at the end of a long spur line fed from Stratford 220 kV bus resulting in high voltage. The Stratford 220 kV bus voltage required managing in order to supress the Taumarunui 220 kV bus voltage. • Without synchronous generators to absorb reactive power, removing circuits was the only option for managing high voltages in the region. In the case, the current practice of removing a Huntly-Stratford 220 kV circuit or Brunswick-Stratford 220 kV circuit could be used to manage voltage. Alternatively constraining on Stratford generation to manage the voltage at Stratford 220 kV bus could be considered. • In this study, high voltages in the Taranaki region are more prevalent in the winter 3150 MW (13:00, 2450 MW North Island PV) scenario than the summer 3000 MW (16:00, 2280 MW North Island PV) scenario. This was due to Stratford G21 being in service and providing reactive support in the summer 3000 MW (16:00, 2280 MW North Island PV) scenario. High voltages in the Taranaki region are shown in the heat maps below (Figure 17 and Figure 18). The study demonstrated that buses connected to Taumarunui 220 kV experienced voltages approaching 1.05 pu. Disconnection of Taumarunui-Te Kowhai 220 kV circuit increased the voltage further. In contrast, the parallel 220 kV path through the central North Island from Bunnythorpe through Whakamaru to Huntly Power Station, did not show high voltage issues in any of the studied scenarios. The remaining synchronous generators at Tokaanu, Whakamaru and Wairaki area regulate voltage at those buses.

Figure 17: Central North Island 220 kV bus voltages Figure 18: Central North Island 220 kV bus voltages summer 3000 MW (16:00) scenario summer 3000 MW (16:00) scenario – TMN-TKH-1 contingency

North Island 110 kV network The central North Island region has abundant hydro generation and geothermal generation making management of high voltages in this region less challenging. The existing high voltage management strategy of removing one of the lightly loaded 220 kV transmission circuits can also be employed to assist in voltage management of the central North Island 220 kV system. The summer 3000 MW (16:00, 2280 MW North Island PV) scenario showed managing 110 kV bus voltages was challenging due to a lightly loaded long spur circuit and absence of voltage regulation capability at the remote ends of the circuit. Analysis of the winter 3150 MW (13:00, 2450 MW North Island PV) and summer 3000 MW (16:00, 2280 MW North Island PV) scenarios showed the following issues in central North Island: • The summer 3000 MW (13:00, 2450 MW North Island PV) case showed that with high PV generation the 110 kV circuits from Bunnythorpe (through Mataroa,

Ohakune, and Ongarue to Arapuni) become very lightly loaded and voltages are high. • A contingency of Mataroa-Ohakune 110 kV circuit placed Ohakune 110 kV bus at the end of a long lightly loaded spur and increased voltage significantly. • To manage voltage under this contingency, the voltage at Arapuni 110 kV North bus would need to be controlled. Constraining Arapuni generation on or running units in TWD to manage voltage could be considered. • Pakuranga-Whakamaru-1 220 kV circuit could be removed to assist managing upper North Island voltages. Removal of this circuit had a small impact on high voltages seen in this area. • No issues were identified in the winter 3150 MW (16:00, 2280 MW North Island PV) scenario in this region, due to availability of Arapuni generation and a higher load along the Bunnythorpe to Arapuni 110 kV buses. Figure 19 and Figure 20 show heat maps of the 110 kV voltage profile in the central North Island region. They show the Ohakune area has voltage approaching 1.05 pu. There are no voltage regulation devices in the Ohakune area to absorb the reactive power generated by a 110 kV lightly loaded transmission circuit.

Figure 19: Central/Lower North Island 110 kV bus Figure 20: Central/Lower North Island 110 kV bus voltages summer 3000 MW (16:00) scenario voltages summer 3000 MW (16:00) scenario – MTR- OKN-1 contingency

Upper South Island The upper South Island region is supplied through the 220 kV transmission system from Islington. The region has very little generation, with only a few small generators embedded in the distribution network. The region relies on shunt capacitor banks and reactors in Blenheim and Stoke to provide steady state reactive power support. The STATCOM and SVC’s at Kikiwa and Islington provide the dynamic support to regulate transmission voltages in the region. Managing high voltages in the upper South Island during extreme light load conditions is challenging but can be managed with the current practice of removing one of the lightly loaded 220 kV transmission circuits connecting to the region. The study showed: • The upper South Island is fed by long transmission lines and the lack of generation in the area made it difficult to manage voltages. The Kikiwa STATCOM provided reactive power absorption to manage voltage in the area. • Westport, Waimangaroa and Inangaua are supplied at the end of two spur lines from Kikiwa. With high PV penetration these circuits were very lightly loaded. • With all reactive power support plants in service in the upper South Island, voltages were able to be maintained to an acceptable operating level.

• A contingency of Kikiwa STATCOM left the upper South Island with little reactive power support resulting in high voltages along the 110 kV circuits from Kikiwa to Westport. • A contingency of Kikiwa T2 interconnecting transformer resulted in high voltages along the upper South Island 110 kV network. The Kikiwa STATCOM was lost along with the interconnection between Kikiwa 220 kV and 110 kV buses. The resultant grid connection to Westport was a lightly loaded spur from Stoke 110 kV, producing high voltages, progressively increasing along the circuits to Westport 110 kV bus. • Removing circuits from Islington (as per the existing practice) did not have a significant effect on managing voltages during a Kikiwa STATCOM or Kikiwa T2 interconnecting transformer contingency. • Tapping the Stoke T7 interconnecting transformer to suppress the Stoke 110 kV improved voltage at Westport. However, doing so pre-contingently (to maintain reasonable post-contingent voltages) resulted in pre-contingent 110 kV voltages below 1 pu. Removing a Kikiwa-Stoke 220 kV circuit also improved voltage along the 110 kV system. • Figure 21 (below) shows a heat map of voltages in the upper South Island region with all plant in service. Figure 22 shows a heat map of the voltage profile in upper South Island region following the contingency of Kikiwa T2 interconnecting transformer. Voltage in the region went above 1.05 pu after the contingency of disconnecting the Kikiwa STATCOM. The Kikiwa STATCOM is the only dynamic reactive power regulating device in the region.

Figure 21: Winter 3150 MW (13:00) power-flow Figure 22: Winter 3150 MW (13:00) power-flow upper South Island voltage heat map upper South Island voltage heat map – KIK STC

contingency

4.3.4 Evaluation of over-voltage management strategies

4.3.4.1 Existing light load management Typically, existing high voltage management strategies are effective at managing high voltage arising from high PV generation. However, there are key differences between night time low load scenarios and a lightly loaded system during high PV generation. The differences are discussed below. The assumption used for this study is that PV will generate at unity power factor. PV generation was not scheduled to generate reactive power in steady state. Loads on the power system are generally inductive; i.e. they absorb reactive power. Therefore, PV generation produces active power to supply the active power loads locally, but does not provide reactive power. Reactive power demand is assumed to be met by sources within the distribution and transmission systems. Comparing similar net loads6 between a high PV generation scenario and night time trough scenario, the reactive power demand seen at the GXPs is expected to be greater in a high PV generation scenario than a normal night time trough scenario. As PV generation increases, net load would continue to reduce. The reactive power generated by lightly loaded transmission circuits will eventually exceed the load reactive power demand causing a net increase in reactive power in the transmission system. At this point, transmission system voltages will increase the requirement for voltage regulation to hold voltages down to an acceptable level. Our analysis indicates that the night time trough demand scenario will have a worse high voltage condition than a similarly loaded high PV generation scenario. The power system should have the ability to manage high voltage during high PV generation if existing management strategies can effectively manage the night time trough period. This comparison only applies while the high PV generation and night trough cases have similar net loads. When increasing PV generation results in a lower net load than night trough scenarios, the analysis shows that high voltage issues will be prevalent throughout the power system. Another important consideration is that managing distribution system voltages arising from increased PV generation will also impact transmission system voltage control. The analysis in this study did not consider changes to GXP reactive power loading due to PV generation in distribution networks. In practice, distribution networks will face line charging and high voltage issues along their feeders due to increasing PV generation which will impact reactive power loadings seen at transmission system GXPs.

6 Net Load represents the power supplied by conventional synchronous generation and is defined as Load MW - PV Generation MW.

The voltage management strategy of distribution networks has the potential to impact transmission voltage control. As PV generation increases in the system, understanding the effect on reactive power loading at GXP’s may be important for the system operator. While PV generation forecasting tools will need to be developed to predict active power demand requirements, understanding the effect on reactive power demand could become just as important. It will become important for distribution network operators to have clear voltage management strategies visible to the system operator.

4.3.4.2 PV generation voltage control Displacing synchronous generation by high PV generation is effectively removing one of the most critical ancillary services provided by synchronous generation; that is, the ability to provide steady-state and dynamic voltage support. PV inverters do not provide the same level of voltage control as synchronous generation. Even if PV generators could provide reactive power regulation, PV reactive power output would be restricted by local distribution voltage management practices having little effect in managing transmission system voltages. In addition, the system operator would need a certain level of visibility to utilise PV generation reactive power capability to manage transmission voltages. The summer scenarios with PV generation exceeding 3000 MW resulted in only a small amount of synchronous generation available in the North Island. This would leave the power system with little capacity to absorb and regulate the reactive power present in the power system, making transmission voltages increasingly difficult to manage.

Removing circuits in the day time versus night time As discussed in subsection 2.2.3, removal of circuits is a method used by the system operator to manage high voltages during light load, typically at night. In the existing power system, the impact on security is minimal because the return of circuits to service can be co-ordinated to comfortably supply a morning ramp up. Removing circuits in the day time due to high PV generation may be more challenging. Factors that may complicate the removal of circuits for daytime voltage management are: • Managing operational procedures such as returning circuits to service during the evening load ramp up while PV generation is simultaneously ramping down due to sunset Note: An evening ramp rate can be much faster than a morning ramp rate, as indicated in the report: Effect of Solar PV on Generation Dispatch in New Zealand.

• Rapid increase in power transfer from loss of PV units due to system faults, resulting in increased transmission circuit loadings

5 VOLTAGE RIDE THROUGH CAPABILITY OF SOLAR PV INVERTERS 5.1 Introduction Larger voltage fluctuations during routine power system switching events and system faults are expected as solar PV penetration level increases. The displacement of synchronous generators connected to the transmission system will reduce the system operator’s ability to manage transmission voltage during and following power system events. In subsection 5.3, fault levels are used to demonstrate the weakening of the transmission system as solar PV penetration increases. The effects of this weaker system on voltage steps during routine switching events are investigated. Transpower’s ongoing ability to manage these voltage steps is confirmed, provided our recommendations are adopted. Subsection 5.4 extends these ‘normal operation’ findings to consider the dynamic voltage ride-through response of solar PV inverters to transient fault voltages in a system weakened by their presence. This section considers low voltage ride-through behaviour due to faults on the network and high voltage ride-through behaviour due to loss of reactive plant. The risks of under- and over-frequency events and an AUFLS tripping are discussed.

5.2 Definitions

5.2.1 System strength Power system voltages fluctuate during system faults and routine events (such as switching capacitor banks and transmission lines in and out of service). Terms referring to ‘strength’ are used to describe the relative amount of voltage fluctuation post-event. A power system that has little voltage fluctuation after an event is said to be a “stronger system” than one experiencing larger fluctuations, which can be described as a “weaker system”. A power system is “stronger” when voltage is more resistant to change during events. The underlying characteristic determining system strength is the equivalent impedance of the power system. Increasing solar PV penetration levels will indirectly influence system strength by changing the relative system impedance through the displacement of synchronous generators. See Appendix A2.1 for a technical explanation. System strength can be deduced in two ways: • The short-circuit current in kA • Voltage step These are described below.

5.2.2 Short-circuit current Short-circuit current is measured in kA. It is sometimes expressed as fault current, or as short-circuit power, and is measured in MVA. Short-circuit current is the amount of current flowing from the power system into a point that is unintentionally short-circuited to ground. Synchronous generation (e.g. hydro, thermal, CCGTs, geothermal, some wind) and inverter-based generation (e.g. some wind and solar PV) are the primary sources of fault current. It follows that the total fault current changes as generators go online/offline. Changes in total fault current can be used to assess system strength. A decrease in fault current indicates the system has become weaker and that larger voltage fluctuations can be expected.

5.2.3 Voltage step A voltage step is the difference in voltage at any bus from before a routine event occurs to the time voltage regulation acts to restore the voltage to pre-event levels. Routine events include switching into service voltage support such as the Otahuhu 100 MVAr capacitor bank, taking circuits in/out of service and load shifting. The voltage step caused by a regular event may change in size when the underlying grid changes (e.g. closing a system split or connecting more generating units). If the voltage step has increased from before the event to after the event (i.e. the grid change) the system is weaker. Figure 23 illustrates a voltage step before and after a change in the grid (which weakens the system).

V(pu)

Difference in V-step after a grid change

V-step

V(pre-event) Regulated Voltage Time Switching Event

Figure 23: Changes in regular steady-state voltage steps reflect changes in system impedance and system strength.

5.3 Impact on fault levels and step-voltage management

5.3.1 Background The studies reported in this section confirm the expectation that greater voltage fluctuations during routine events are expected as solar PV penetration levels increase. Fault levels are used to demonstrate the weakening of the transmission system as solar PV penetration increases. The effects of this weaker system on voltage steps during routine switching events are investigated. Transpower’s ongoing ability to manage these voltage steps is confirmed (assuming specific recommendations are adopted).

5.3.2 Study methodology

5.3.2.1 Assumptions The following study-specific assumptions were made: • PV generation was modelled as being equivalent to generation with equivalent distribution network impedance connected to the GXPs. • Each generator’s fault current contribution was described by its rated voltage, rated MVA and reactance. Generator capability data was used when available. • Power electronics-based generation and devices with no capability data (i.e. some wind farms, STATCOMs, SVCs and solar PV) were assumed to limit fault current to its rated current. • PV generation was assumed to only contribute fault current when generating power. • The ‘Classical’ (aka ANSI) fault calculation method was used. • The assumptions for grid configuration and the generator dispatch status of the scenarios are described in report Effect of Solar PV on Generation Dispatch in New Zealand. These assumptions result in average operational fault levels being calculated. The following were considered out of scope for this study: • Effect of PV generation on HVDC operation and on voltage management related to HVDC contingency. • Power-flow Scenarios The power-flow scenarios used for this analysis were derived as discussed in subsection 3.2 and selected based on the levels of PV generation.

5.3.2.2 Fault level analysis method Fault levels were used as a measure for determining how increased PV generation affects system strength and voltage management, to identify regions most affected by the PV generation.

Steady-state power-flow analysis used commercial software. A three-phase, zero impedance bus fault7 was applied to every 220 kV and 110 kV bus in the Transpower network using the Classical fault calculation method. This was completed for each power- flow scenario to observe how bus fault currents change with increasing PV penetration, identifying specific regions where system strength is expected to be most weakened. See subsection 5.3.3.1 for results. Appendix A2.3 contains technical details of these two methods and their differences. Appendix A2.5 provides a sample from the dispatch status table.

5.3.2.3 Voltage step analysis method Voltage fluctuations can be expected to increase in areas weakened by increasing PV generation. The fault level analysis was used to identify these weakened Grid Zones and buses. Specialised switching studies were used to calculate transient voltage steps such as those illustrated in Figure 23 (see Appendix A2.4 for details). Voltage steps were created by switching capacitor banks into service at various buses for the 0 MW and 3100 MW winter Tuesday scenarios. The low nett load makes the network highly capacitive. Therefore, for these switching studies the Pakuranga-Brownhill-Whakamaru 220 kV circuit was assumed to be removed from service to reduce any high voltages resulting from the low nett load.

5.3.3 Fault level study results and analysis

5.3.3.1 Effect on fault current The power-flow analysis approach described in subsection 4.2 was used to investigate in more detail the national results of the previous section. Three-phase, zero impedance fault currents were calculated at every 220 kV and 110 kV bus in the winter Tuesday grid. Two colour map series (shown below) help visualise the change in these fault currents from 0 MW PV to 3150 MW PV (i.e. 07:00 to 12:00); one series for each of the 220 kV and 110 kV networks. Figure 24 to Figure 27 below provide 220 kV and 110 kV change maps for the 3150 MW (12:00) scenario. Appendix A2 contains the complete map series for each of the 220 kV and 110 kV networks. Each ‘fault current change’ map series includes two maps of the entire country for the 750 MW (08:00) and 3100 MW (12:00) scenarios. They also include four zoom-in maps of Grid Zone s 1-4 where the largest decreases in fault current occur. These four maps are for scenarios: 750 MW (08:00), 2050 MW (09:35), 2650 MW (10:30) and 3150 MW (12:00). Each change map reflects the change in fault current from the 0 MW scenario to that particular scenario, which for figures 24 to 27 is the 3100 MW scenario. Cooler colours

7 A three-phase, zero impedance bus fault is when all three phases of a substation bus (e.g. 220 kV, 110 kV, 33 kV bus) have been unintentionally connected directly to ground (i.e. 0 kV) through a zero impedance short-circuit.

represent a decrease in fault current. Warmer colours represent an increase in fault current. With the 3150 MW scenario for example, the fault current at the Whakamaru 220 kV bus drops -6386 A from 21,056 A at 07:00 (with 0 MW of solar PV) to 14,670 A at 12:00 (with 3100 MW of PV). These power-flow results and the results in the previous analysis confirm the expectation that some areas of the power system will become weaker as the amount of installed solar PV capacity increases. The areas expected to be most weakened by solar PV capacity are where synchronous generation is displaced – namely the 220 kV network in North Island Grid Zone 4 and South Island Grid Zone 13. This weakening is reflected by these zones having the greatest overall decreases in fault levels. See, for example, the above fault current values for the Whakamaru 220 kV bus. However, the 220 kV network in Grid Zone 1, Grid zone 2 and several other 220 kV buses throughout New Zealand experience a small nett increase in strength with respect to the 0 MW scenario. For example, the fault current at the Albany 220 kV bus increases slightly by 439 A from 10,111 A to 10,550 A. A large percentage of the solar PV is installed in Grid Zone 1 and Grid Zone 2 that contributed to this slight increase in fault current. This is more noticeable in Grid Zone 1, but from south of Auckland the fault level decreased. The fault levels in the 110 kV network are much less affected by the displaced synchronous generation. Buses in Grid Zones 3, 4, 13 and 14 only experience a marginal decrease in strength. Buses in other Grid Zones either experience no material change or a marginal increase in strength. This was due to the 110 kV network being electrically further from the displaced synchronous generation and closer to the solar PV installed in the low voltage distribution network (i.e. 33 kV and lower). These results signal a shift in the location of system strength towards the low voltage distribution network with the 110 kV network (and lower voltage levels) fault level remaining the same or marginally decreasing and the 220 kV network fault level decreasing more significantly, especially at the generating buses. This change in the location of high fault currents has implications for protection settings and for the overall voltage management strategy.

Figure 24: Change in fault currents from 0 MW to 3150 MW – Figure 25: Zoom on Grid Zone 1-4. Change in fault currents 220 kV network from 0 MW to 3150 MW – 220 kV network

Figure 26: Change in fault currents from 0 MW to 3150 MW – Figure 27: Zoom on Grid Zone 1-4. Change in fault currents 110 kV network from 0 MW to 3150 MW – 110 kV network

5.3.3.2 Effect on voltage step Table 2 shows the change in voltage step when the study power system goes from 0 MW installed PV to 3150 MW installed PV. Voltage steps were calculated using the switching study process described in subsection 5.3.2.3. Voltage steps are only reported for the buses at which the switching event occurred because the voltage step is greatest at the location of the event. With respect to switching event locations, the Whakamaru 220 kV (WKM220) and Twizel 220 kV (TWZ220) buses were selected because they experienced the largest reductions in fault current (and hence system strength) in the North Island and South Island respectively. From the 0 MW scenario to the 3150 MW scenario their fault currents reduced by -6,386 A and -6,363 A respectively. All other switching event locations were selected for being buses with switchable capacitors or for having weak strength (as indicated by their low fault currents relative to other buses).

Table 2: Change in voltage step and system strength relative to 0 MW scenario, caused by switching into service the largest available capacitor at that bus.

Relative Change in System Voltage Step Fault Current (A) Strength Magnitude Event MVAr Switched 3150 M Island 0 MW 3100 MW 0 MW Strength Location In To Service W (Change in Fault Current) North ALB110 50 MVAr 1.95% 1.88% 13,422 14,145 723 Stronger North ALB220 100 MVAr 2.45% 2.47% 10,111 10,550 439 Stronger North BOB110 50 MVAr 2.98% 3.13% 8,440 8,272 -168 Weaker North HEN220 75 MVAr 1.89% 1.84% 10,134 10,573 439 Stronger North HEN220 100 MVAr* 2.53% 2.46% 10,134 10,573 439 Stronger North OTA220 100 MVAr 1.98% 2.04% 12,512 12,135 -377 Weaker North WKM220 100 MVAr* 1.28% 1.86% 21,056 14,670 -6,386 Weaker NI Bus with greatest change

South BDE110 5 MVAr 2.35% 2.34% 2,911 2,787 -124 Weaker South NMA220 50 MVAr 1.50% 2.04% 8,266 5,435 -2,831 Weaker South STK110 20 MVAr, on 2.58% 2.74% 4,049 3,658 -391 Weaker STK-T7 Tertiary Winding (11 kV) South TWZ220 50 MVAr* 0.90% 1.52% 15,244 8,881 -6,363 Weaker SI Bus with greatest change

* indicates a simulated capacitor switching event that is larger than existing installed capacitors at that bus. The voltage step results in Table 2 indicate that installing up to 3150 MW of solar PV capacity will not materially cause the voltage step performance to deteriorate. The WKM220 and TWZ220 buses were weakened the most in the power system. As discussed

previously, the cause is the displacement of synchronous generation units by increasing solar PV capacity. But these voltage steps are still within the manageable level. These voltage step results are for winter scenarios. Summer is expected to present a more difficult situation because of overall lower net loads. At summer solar peak, 3500 MW of PV is expected, resulting in only 750 MW of net load (refer Figure 6), below the 2000 MW winter net load. In the absence of other factors, the additional solar PV MW would force even more synchronous generation offline, weakening the system and increasing the voltage step. However, other factors such as steady state voltage regulation can limit the uptake of PV generation before the voltage step presents itself as a limiting factor.

5.3.4 Fault level and voltage step study limitations The fault level and voltage step study results have limitations that must be considered when reading the above analysis. In the power-flow network model used for these voltage management studies all GXP PV generation profiles (see subsection 3.1) are modelled using single generating units, connected to GXPs via transformers having a 10% impedance. In reality, each generating unit is an aggregate representation of all solar PV panels installed throughout the distribution network connected to that GXP. The contribution of fault current by the PV generation will be different and expected to be lower.

5.4 Effect of transmission faults on inverter ride through capability This subsection presents analysis of the effect of power system events on the ability of PV generation to ride through faults. Subsection 5.3 shows that increased PV generation results in a weaker power system that is more susceptible to voltage disturbances. Depending on the type of power system event, PV generators can experience low voltage or high voltage at their terminals. The ability of the PV generation to remain connected during and after the event is important to ensure that the power system can recover and maintain stability.

5.4.1 Study methodology

5.4.1.1 Time domain analysis PV generation voltage ride through analysis was carried out with time domain simulation software. The base power-flow scenarios used for this analysis are discussed in subsection 3.2. The load model used in the dynamic simulation was constant current for P and constant Impedance for Q. The time domain simulation was carried out to determine the ability of PV generation to ride through a power system event. Various types of credible power system events were created to study the effect and to analyse the subsequent impact if the PV generation was unable to ride through an event.

5.4.1.2 Inverter dynamic models Dynamic models of key power system components were required to conduct time domain analysis. The PV generators’ dynamic behaviour used in this study was based on benchmark testing performed on 3 different inverter types (Inverter A, B, and C). Computer models were built to represent the three PV generation types. Information from benchmark testing was used to validate the computer models, to ensure the models could predict the dynamic behaviour to a suitable level for the study. Details on the PV generation characteristics and the model representing each type of PV generation are in Appendix A3 – Inverter models. The voltage ride through characteristics of Inverter A, B and C are in Figure 28. The study showed: • Inverter A will trip after 1 second below 170 V (0.74 pu), or 2 seconds below 180 V (0.78 pu). • Inverter B is most resilient to Low Voltage, only tripping after 2 seconds below 180 V (0.78 pu). • Inverter C is most sensitive to low voltage, tripping instantaneously below 160 V (0.70 pu).

• All three inverters had a 2s high voltage trip ranging between 258 V (1.12 pu) and 270 V (1.17 pu) voltage. Inverters A and B also had faster trips at 280 V (1.217 pu) in 10 ms and 265 V (1.152 pu) in 200ms respectively.

1.40

1.20

No Trip Zone 1.00

0.80

Inverter A 0.60 Inverter B Voltage (pu) Voltage Inverter C

0.40 Inverter A and B No Trip Zone Inverter B No Trip Zone

0.20

0.00 0 0.5 1 1.5 2 2.5 Voltage Disturbance Duration (s)

Figure 28: Inverter Voltage Ride Through Characteristics The approximate proportion of total PV generation across New Zealand assigned to each inverter type was as follows8: • Inverter A: 17% • Inverter B: 71% • Inverter C: 12%

5.4.1.3 Contingencies Two types of contingencies were studied in this analysis: 1. Line faults to study low voltage ride through 2. Loss of reactive plant to study high voltage ride through To investigate low voltage ride through, a conservative approach of applying three-phase zero-impedance faults for 120ms was taken. Faults were applied to 110 kV and 66 kV lines throughout the power system model. Contingency screening was carried out to identify the most severe fault locations with respect to the effect on PV inverters in the North and South Island. The resultant worst case 110 kV and 66 kV lines were: • Otahuhu-Penrose 110 kV circuit, Otahuhu bus end • Hororata-Kimberly-Islington 66 kV, Islington bus end For high voltage ride through, the reactive power plant operating in lagging mode (absorb reactive power) was disconnected to create a rise in system voltage. The reactive plant contingencies in this analysis were:

8 The distribution of inverter types was based on the manufacturer market share data in other countries.

• Albany SVC • Penrose STATCOM • Kikiwa STATCOM • Kikiwa T2 (loss of both the STATCOM and 220/110 kV interconnecting transformer at Kikiwa)

5.4.2 Study results

5.4.2.1 Otahuhu 110 kV line fault Applying a short circuit fault close to Otahuhu 110 kV bus depresses the voltage at the fault location to 0 pu for the duration of the fault. Surrounding buses see a voltage depression, the magnitude of which depends on the strength of the system and the electrical distance from the fault location. Figure 29: winter 3150 MW OTA 110 kV fault simulation – Bus voltage and Inverter LVRT characteristics show the dynamic simulation of the Otahuhu 110 kV fault in the winter 3150 MW (13:00) scenario. The plot shows the voltage depression during the fault triggering inverter C’s instantaneous trip at 0.7 pu voltage. The simulation also shows voltage quickly recovers after the fault, with no risk of triggering any of the inverters 1 second or 2 second low voltage trips.

1.2

0.8

0.6

Bus Voltage pu 0.4

0.2

0 0.5 1 1.5 2 2.5 3 3.5 Time (s)

Inverter C LVRT Characteristic OTA 110 kV WIR PV OTA PV WKM PV BPE PV Inverter A LVRT Characteristic Inverter B LVRT Characteristic

Figure 29: winter 3150 MW OTA 110 kV fault simulation – Bus voltage and Inverter LVRT characteristics

Figure 30 below shows the lowest value that PV generation 11 kV bus voltage drops to at selected GXP’s across the North Island during the simulated Otahuhu 110 kV line fault. The low voltage protection setting of inverter C (0.7 pu) is shown as a red dotted line. The result shows that as PV generation increases, the system strength is reduced and the voltage depression due to a fault at Otahuhu 110 kV propagates further and more severely throughout the system. In winter with 3150 MW of PV generation, PV generation as far as Bunnythorpe may see 0.7 pu voltage during an Otahuhu 110 kV fault.

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0.8 Inverter C LV Trip 0.7

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0 WIR BOB OTA BRB HAM WKM WRK SFD BPE HAY 11 kV PV bus location 0 MW 750 MW 1750 MW 2650 MW 3150 MW Winter 7:00 Winter 8:00 Winter 16:00 Winter 10:30 Winter 13:00

Figure 30: Bus voltage during an Otahuhu 110 kV line, three phase fault – winter scenarios Figure 31 below shows the total amount of PV inverter MW tripped for different PV generation penetration levels. The results show that as PV increases, the potential PV generation lost due to an Otahuhu 110 kV fault increases due to: • More PV generation at each GXP • Voltage depression propagating further and more severely due to a weakened system The winter 750 MW PV generation scenario shows that 50 MW of PV generation was potentially lost due to a 110 kV fault near to Otahuhu. The amount of PV generation potentially lost increased as PV generation increased, with up to 250 MW of PV being potentially tripped in the 3150 MW PV generation scenario. PV generation lost due to system fault at Otahuhu was about 130 MW, exceeding the North Island AC CE risk of 120 MW when PV generation reached 1750 MW mark. This indicates that a system fault at Otahuhu could potentially cause the system frequency to drop below the 48 Hz CE frequency limit triggering Automatic Under-Frequency Load Shedding (AUFLS). In winter with 3150 MW of PV generation the potential PV generation lost due to a system fault at Otahuhu was approximately 250 MW, exceeding the North Island system AC risk (both CE and ECE risks9). This would require frequency management to ensure system frequency will not deviate outside the 47 Hz statutory limit. The largest North Island AC Extended Contingent Event (ECE) risk in the winter 3150 MW PV generation scenario is estimated to be 200 MW.

9Effect of solar PV on Frequency Management in New Zealand

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0 0 MW 750 MW 1750 MW 2650 MW 3150 MW -100 Winter 7:00 Winter 8:00 Winter 16:00 Winter 10:30 Winter 13:00

-200 Figure 31: solar PV Inverter trip MW for an Otahuhu 110 kV line fault – winter

A similar conclusion to the winter scenarios above can be drawn for the summer PV generation scenarios. The potential loss of PV generation due to a system fault exceeded the AC CE risk when PV generation reached 2300 MW. This would likely trigger AUFLS if such an event were to occur. In the 2900 MW and 3000 MW scenarios the potential loss of PV generation due to a system fault exceeded the system AC risks (both CE and ECE risks), necessitating frequency management to avoid frequency falling below 47 Hz.

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0 AC ECE Risk 650 MW 2300 MW 2900 MW 3000 MW Active Power (MW) -50 Summer 8:00 Summer 10:00 Summer 11:00 Summer 16:00

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-200 Figure 32: solar PV Inverter trip MW for an Otahuhu 110 kV line fault – summer.

5.4.2.2 Islington 66 kV line fault In the South Island, a short circuit fault close to Islington 66 kV line was identified as the most critical contingency. Figure 33 shows a result similar to the North Island. With high PV generation scenario, a three phase zero impedance fault at Islington 66 kV bus can cause buses as far south as Invercargill to drop below 0.7 pu voltage.

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0.8 Inverter C LV Trip 0.7

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0 SBK ISL KIK STK MCH OTI TIM TWZ OAM HWB INV 11 kV PV bus Location

0 MW 750 MW 1750 MW 2650 MW 3150 MW Winter 7:00 Winter 8:00 Winter 16:00 Winter 10:30 Winter 13:00

Figure 33: Bus voltage during an Islington 66 kV line, three phase fault – winter scenarios

The PV generation penetration level in South Island is low compared to the North Island as there is less rooftop PV generation. Consequently, the risk posed by the disconnection of PV generation due to a system fault is much lower. Under all winter and summer scenarios, the PV generation disconnection risk is estimated to be 80 MW at the most, below the South Island AC CE risk. The frequency reserve procured to cover the AC CE risk should be adequate to mitigate the PV generation potentially lost due to a system fault. The summary of the simulation results are shown in Figure 34 and Figure 35.

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0 0 MW 750 MW 1750 MW 2650 MW 3150 MW -100 Winter 7:00 Winter 8:00 Winter 16:00 Winter 10:30 Winter 13:00

-200 Figure 34: solar PV Inverter trip MW for Islington 66 kV line fault – winter

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Total Inverter Trip MW 100 Bipole North MW AC CE AC ECE Risk 0 Active Power (MW) 650 MW 2300 MW 2900 MW 3000 MW Summer 8:00 Summer 10:00 Summer 11:00 Summer 16:00

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-200 Figure 35: solar PV Inverter trip MW for ISL66 line fault – summer Sunday 10/01/2016

5.4.2.3 Loss of reactive plant As discussed in section 4, high PV generation can push system voltage high, requiring reactive power compensation devices to absorb reactive power to manage the voltage down to an acceptable level. A disconnection of the devices will cause the post-event system voltage to increase. A selection of credible contingent events is applied to investigate the voltage performance under high PV generation scenarios. The voltage rise was assessed against the inverter over-voltage trip settings, assuming a worst case pre-contingent voltage of 1.05 pu. Key voltage rise criteria in this study are: • 15.9% for 10 ms to avoid Inverter A 1.22 pu trip • 9.7% for 200 ms to avoid Inverter B 1.15 pu trip

In the upper North Island, disconnection of Penrose STATCOM and Albany SVC does not cause significant voltage rise. PV generator terminal voltages did not rise more than 5%, posing no risk of encroaching PV inverter high voltage trip settings. All the PV generation is expected to remain connected following these contingent events. In the upper South Island, a contingency involving the disconnection of Kikiwa STATCOM posed the greatest risk to the system. A direct disconnection of Kikiwa STATCOM or the disconnection of Kikiwa T2 interconnecting transformer resulting in the disconnection of Kikiwa STATCOM will cause the system voltage in that vicinity to rise more than 12% transiently. Although the voltage rose beyond 9.7%, it decayed within 200 ms so it did not cause any inverter disconnection. All PV generation is expected to remain connected following a contingency involving Kikiwa STATCOM. Figure 36 below shows the voltage10 transient at the Murchison 11 kV PV bus for a loss of Kikiwa T2 in the winter 3150 MW (13:00) scenario, and the high voltage ride through characteristics of Inverter A and B.

1.25

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1 0 0.5 1 1.5 2 2.5 3 3.5 4 4.5 5 Time (s) Inverter A HVRT Characteristic Inverter B HVRT Characteristic MCH 11 kV PV bus voltage (Winter 3150 MW) Figure 36: Murchison PV bus voltage increase during Kikiwa T2 contingency

5.4.3 Analysis

5.4.3.1 Effect of PV Inverter fault ride through capability on frequency management The study results showed that, as PV generation increases on the power system, two phenomena occur that affect the total PV potentially lost on the system: • Voltage suppression during faults propagates further throughout the system due to increased PV resulting in a weaker power system. • PV generation increases, leading to a greater amount of PV generation being at risk of disconnection (due to PV inverters being unable to ride through a voltage disturbance).

10 Actual simulation output voltage was scaled to represent a worst case of 1.05 pu pre-contingent voltage

While the amount of PV generation potentially lost due to a system fault increases as PV generation is increased on the system, the AC and DC frequency risks decrease. With high PV generation, thermal units which may set the AC CE risk at around 350 MW are no longer dispatched, leaving 100 MW units to set the AC CE risk. Similarly, AC ECE risk reduced as PV generation increased. High PV generation in the North Island reduces DC transfer north, resulting in the reduction of DC risks as well.Current frequency management practices would see sufficient reserves purchased to cover for the loss of the AC and DC risks. High PV generation reduces these risks and consequently reduces the reserves procured on the system. Results show that with PV generation going above 1750 MW, the potential loss of PV generation due to faults begins to exceed the AC CE risk, meaning the frequency reserve procured to cover CE risk will not be adequate to prevent system frequency dropping below 48 Hz. When PV generation goes above 2900 MW, the potential loss of PV generation due to faults starts to exceed the AC ECE risk, meaning additional frequency reserve would be necessary to prevent system frequency dropping below 47 Hz.

5.4.3.2 Importance of PV generation voltage ride through capability The capability of PV generation to ride through power system events is essential for ensuring secure and reliable system operation. Study results indicate that inverter C will not be able to ride through system faults on the 110 kV and 66 kV transmission systems and may pose a risk to system frequency, if PV generation of this technology type reaches large enough levels. At the time of writing, it has not been determined how this risk will be managed by the system operator. To ensure power system security an expected loss of PV generation for system events will need to be determined and classified accordingly as CE or ECE events. Classification of the risks will determine the mitigation measures the system operator will employ to manage the risk. The risk can be reduced by ensuring that domestic PV installations have inverter low voltage and over-voltage protection settings that are compliant with AS/NZS 4777.2:2015 [4]. This will ensure that all PV generators can ride through system faults and will not pose secondary problems for system operation.

6 THE EFFECT ON VOLTAGE STABILITY

This section presents the analysis of voltage stability of a system with 4 GW of installed capacity PV generation with the existing power system topology. The analysis considers the effect on voltage stability as a result of the displacement of conventional generation with roof-top solar PV, and the resultant reduction of loading on transmission assets.

6.1 Background

6.1.1 Importance of voltage stability to system operation New Zealand has long transmission circuits connecting remote generation sources to the load centres, making it critical that we maintain a stable voltage across the transmission system. Increasing intra-regional power transfers in the system from remote generation to load centres can cause voltage depression in the receiving region. Extremely high levels of power transfer or extreme contingencies could lead to voltage collapse in a load centre. Ultimately, this could result in what is referred to as a “blackout”, caused by insufficient reactive power support in the system. Voltage collapse is a manifestation of voltage instability in the system. The static security analysis in this section is based and conducted as quasi-static voltage stability studies. Two common methods that are available to determine voltage stability are the PV curve and QV curve analysis methods. The PV curve analysis method determines the voltage on a load bus as a function of real power demand or sum of load demand. PV curve computation is analysed to determine the stability margin for a particular transmission corridor that when operated within the margin will maintain voltage stability. The QV curve analysis method determines the reactive power injection of a load bus as a function of its voltage. QV curve computation is analysed to determine the sensitivity of the bus voltage to reactive power injection (or reactive load) and also the reactive power margin at that bus, which is how much the system can be stressed by reactive load increase at that one bus before it becomes unstable.

6.2 Study methodology

6.2.1 Study networks The regions/interfaces assessed during these voltage stability studies are: • Upper North Island comprising Grid Zones 1 – 2 • Upper South Island comprising Grid Zones 9 – 12 These two regions have little local generation to rely on to supply the demand, hence they rely on remote generation of electrical power transmitted via the transmission circuits. Voltage stability limits can be a binding constraint, limiting the capability for these two regions to import electrical power to meet local demand. In addition, the

studies conducted in report Effect of Solar PV on Generation Dispatch in New Zealand identified that these two regions have the highest PV generation proportions of all New Zealand regions.

6.2.2 Power-flow case files studied Selected power-flow case files described in subsection 3.1 were studied and compared during this voltage stability assessment.

6.2.3 Voltage stability study assumptions In addition to the study assumptions listed in section 3, other assumptions taken for the voltage stability study were: • No corrective actions were factored in from the existing special protection schemes (e.g., AUVLS, emergency automated control systems and the like). • All reactive power limits for generators, SVC/STATCOM and synchronous condensers were modelled as per information provided by the Asset Owner. • There was no post-event switching of shunt capacitors. • There was no on-load tap changer (OLTC) action. • Specific industrial loads would not increase when performing transfer analysis.

6.3 Study results This section presents the culmination of findings attained from voltage stability studies conducted on upper North Island and upper South Island regions.

6.3.1 Effect of PV generation on voltage stability This study is based on PV generation modelled as embedded within the distribution network. When PV generation increases during the day the result is a net reduction in load at the sink (load end) of the interface. This will enable the source (generation end) to serve more demand before reaching the voltage stability limit, after which voltage instability occurs. The value of sink is defined as the voltage stability load limit and refers to the value of demand that can be supplied stably by local generation within the region and from generation outside the region via the transmission system.

6.3.1.1 Upper North Island winter scenario For the upper North Island region under a winter study scenario, Figure 37 illustrates the interface MW flow and the voltage stability load limit at the transfer limit for the most limiting contingency in each of the power-flows studied.

3000 1400.00 UNI PV Profile 2800 1200.00 2600

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400.00 (MW) PV Profile UNI and load profile load and (MW) 1400 200.00 1200 Voltage stabilityVoltage load limit, interface flow, 1000 0.00 6:57 8:09 9:21 10:33 11:45 12:57 14:09 15:21 16:33 17:45 Time of day UNI interface MW flow UNI voltage stability load limit UNI load profile

Figure 37: Values of source and sink at the transfer limit in UNI region with a rise in PV generation over the day – winter scenario These results show that the difference between the voltage stability load limit and the actual upper North Island load profile is larger during the middle of the day compared to night when PV generation is zero. When PV generation increased over the day in the upper North Island, it contributed to the increase in voltage stability load limit. Typically, local demand is reliant on remote generation sources. However, with high PV generation the local demand is being supplied mostly by the local PV generation sources. Figure 38 below shows the PV curves calculated for selected buses in the upper North Island region under pre- and post-contingency conditions.

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0.94 1540 1740 1940 2140 2340 2540 2740 Load limit (MW) ALB 220 MDN 220 OTA 220 ALB 220 Post-contingency MDN 220 Post-contingency OTA 220 Post-contingency

Figure 38: UNI region PV curves for selected 220 kV circuits - winter 1300 base case pre- and post-contingency of a HLY-TWH1 220 kV circuit It can be seen from these results that a voltage stability load limit of 2528 MW is calculated for a 3150 MW (13:00) winter power-flow case with a contingency of the Huntly – Te Kowhai 220 kV circuit.

The upper North Island voltage stability load limit increased as PV generation in the region increased. The interesting point to note from Figure 38 is that the upper North Island voltage stability load limit does not increase proportionally with the amount of PV generation within the region as would be expected. This is the result of switching off shunt capacitor banks in the region to manage system over-voltages. Another factor is that PV generation embedded within the distribution network displaces MW but does not displace MVAr as PV generation was modelled with unity power factor. Therefore, the system must still meet the MVAr demands of the region through the interface, which is the transmission system. Figure 39 illustrates the amount of equivalent line charging produced by all the transmission circuits within the upper North Island region, and the resulting shunt capacitor banks which are switched off.

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0 7:00 8:00 11:00 12:00 13:00 14:00 16:00 17:00 18:00 Time of day UNI equivalent line charging UNI shunt MVAr reserve (charging - losses in base case) (un-switched in base case)

Figure 39: UNI equivalent line charging and shunt MVAr reserve thought the day - winter scenario In the 3150 MW (13:00) winter power-flow case, approximately 1120 MVAr of static shunt capacitor banks were switched off in upper North Island. If utilised operationally as load increases, this shunt capacitor banks can be switched in to provide the essential voltage support to increase the voltage stability load limit. The change in voltage as load increases is considered quasi-static, which is a change over a matter of tens of minutes or hours. This shows that switching of shunt capacitors operationally is easily achievable.

6.3.1.2 Upper South Island winter scenario For the upper South Island region, Figure 40 illustrates the post-contingent load limit for the most limiting contingency in each of the power-flows studied for a winter study scenario.

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900 200.00 USI PV Profile (MW) and load profile load and (MW) 800 100.00 700 Voltage stabilityVoltage load limit, interface flow, 600 0.00 6:57 8:09 9:21 10:33 11:45 12:57 14:09 15:21 16:33 17:45 Time of day

USI interface MW flow USI voltage stability load limit USI load profile

Figure 40: Values of source and sink at the transfer limit in USI region with a rise in PV generation over the day – winter scenario Similar to the upper North Island region, the difference between the voltage stability load limit and the upper South Island load profile is larger during the middle of the day compared to night when PV generation is zero. The effect of PV generation in the upper South Island region is largely reduced in comparison with the upper North Island region due to the assumed distribution of installed solar inverters across the country. In the upper South Island region, the resulting voltage stability load limit is shown in the calculated PV curves of Figure 41.

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0.9 720 820 920 1020 1120 1220 1320 1420 Load Limit (MW) ISL 220 STK 220 TIM 220 ISL 220 post-contingency STK 220 post-contingency TIM 220 post-contingency Figure 41: USI region PV curves for selected 220 kV circuits - winter 1300 base case pre- and post-contingency of a ISL-LIV 220 kV circuit These results show that a voltage stability load limit of 1251 MW could be achieved in the upper South Island region. This voltage stability load limit was calculated for all New Zealand for a 3150 MW (13:00) winter power-flow case.

As with the upper South Island region, the upper North Island region voltage stability load limit increased, as PV generation in the region increased. Shunt capacitor banks were also switched off in the upper South Island region to manage system over-voltages. Figure 42 illustrates the equivalent line charging produced by all the transmission circuits within the upper South Island region, and the resulting MVAr value of shunt capacitor banks which are switched off.

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Figure 42: USI equivalent line charging and shunt MVAr reserve thought the day - winter scenario It can be seen in the 3150 MW (13:00) winter power-flow case that approximately 520 MVAr of static shunt capacitor banks are available to increase the voltage stability load limit when required.

6.3.1.3 Upper North Island and upper South Island summer scenarios The voltage stability load limit and interface MW flow characteristics in the upper North Island and upper South Island regions for the summer scenario follows a similar trend as in the winter scenario. Results from these studies up to the 2900 MW (11:00) summer power-flow case can be seen in Appendix A4. Only power-flow cases up to this MW level were studied as further increases in PV generation would cause the bus voltages to rise to unmanageable levels. To study past this point in the day would either require a change in dispatch methodology to manage voltage, or the installation of additional grid infrastructure.

6.3.2 Effect of PV generation on transmission line loading This subsection presents the effect that 4 GW of installed capacity PV generation would have on the loading of transmission assets within New Zealand’s power system. As PV generation increases during the day the transmission circuits reduce in loading which results in equivalent charging MVAr being produced, as described in subsection 6.3.1.

6.3.2.1 Upper North Island winter scenario Figure 43 illustrates the percentage MVA loading of all high voltage transmission circuits in the upper North Island region for a winter scenario. These results are calculated from the base case under pre-contingency conditions.

Figure 43: Effect of solar PV on line loadings in the UNI region for a winter Scenario This noticeable reduction in circuit loading can be attributed to the equivalent charging effect produced by lightly loaded high voltage transmission lines as explained in subsection 4.1, coupled with the change in load profile throughout the day. An interesting point to note is the rise in percentage loading of the Kaikohe – Maungatapere 110 kV circuits in the centre of the day. These are spur circuits through to Ngawha Springs GXP and the Ngawha geothermal generation station. The increase in loading can be attributed to the MW flow on those lines increasing when PV generation in areas of Northland would be at its highest and would have to flow out of that area of the network. The reduction in loading of high voltage transmission circuits shows how a large uptake of roof-top solar PV in the distribution network could reduce dependency on transmission assets under system intact conditions. However, it is unlikely that regions would reach a situation where energy production and consumption were in balance without there still being need for a transmission system. The transmission system is still needed when the PV generation drops due to cloudy days, solar eclipse and during the night.

6.3.2.2 Upper South Island winter scenario Figure 44 illustrates the percentage loading of all high voltage circuits in the upper South Island region for the winter study scenario. It is important to note that the South Island only makes up approximately 22% of the 4 GW of installed capacity PV generation modelled in these studies. Consequently, high levels of PV generation will have a larger effect on circuit loadings within the upper North Island region, where most PV generation is modelled.

Figure 44: Effect of solar PV on line loadings in the USI region for a winter Scenario The upper South Island showed a reduction in circuit loading in a similar trend to the upper North Island. This can be attributed to the equivalent charging effect produced by lightly loaded transmission lines, coupled with the change in load profile throughout the day.

6.3.3 Effect of PV generation on reactive reserve margin This subsection presents the results from QV curve analysis of a selected group of buses within the upper North Island and upper South Island regions for a winter scenario. The QV curve determines the maximum MVAr that any particular bus in a system can be stressed before voltage collapse occurs. QV curve analysis involves studies on how bus voltages (V) in the system are affected by variations in reactive power (Q). The base case operating point of the system is represented by the x-axis intercept of the curve. The V-Q sensitivity of a bus is the slope of the QV curve at the base case operating point, this is also referred to as the stiffness of the bus. A system is deemed voltage stable if the V-Q sensitivity is positive for every bus in the system, and voltage unstable if V-Q sensitivity is negative for at least one bus.

6.3.3.1 Upper North Island winter scenario Figure 45 illustrates the difference in QV curves for selected 220 kV circuits within the upper North Island region under pre- and post-contingency conditions of a Huntly – Te Kowhai 1 circuit.

Figure 45: UNI region QV curves for selected 220 kV circuits - winter 1300 base case pre- and post-contingency of a HLY-TWH1 220 kV circuit The change in slope of the Marsden 220 kV bus QV curve around the operating point shows the characteristics of the STATCOM in that area when maintaining voltages. Results seen in the QV curve for the upper North Island region show that the reactive reserve margin for the Albany, Marsden, and Otahuhu 220 kV buses is sufficient to withstand the most limiting contingency. The line charging and other reactive power compensation devices provide the necessary reactive power reserve for the region.

6.3.3.2 Upper South Island winter scenario Figure 46 illustrates the difference in QV curves for selected 220 kV circuits within the upper South Island region under pre- and post-contingency conditions of the Islington – Livingston circuit.

Figure 46: USI region QV curves for selected 220 kV circuits - winter 1300 base case pre- and post-contingency of ISL_LIV 220 kV circuit

Results seen in the QV curve for the upper South Island region show that the reactive reserve margin for the Islington, Stoke, and Timaru 220 kV buses is sufficient to withstand the most limiting contingency. The upper South Island region has sufficient reactive power margin to manage voltage stability in the region.

6.3.4 Summary analysis Generation of real power stemming from solar PV connected at lower voltage level buses within distribution networks would essentially net off load within that region, thereby reducing loading on transmission circuits. This reduction would move the MVA loading operating point below that of the surge impedance loading value of the circuit, resulting in production of reactive power in the circuit. This production of reactive power would be much greater than that of the reactive losses in the system, as a result of which the production of reactive power creates equivalent charging in the network. This equivalent charging would circumvent the need for large amounts of shunt capacitance, so long as the solar PV continued to generate real power. In a realistic system, this will not be the case as many variables influence the amount of MW generated from solar PV (such as variability in cloud cover which affects the amount of real power generation, and ambient temperature of the solar PV panels which would influence the efficiency of power output). The calculated load limit achieved under these conditions would be similar to that of the existing system. However, this does not take into account the unused shunt capacitance throughout the system which would have a proportional effect on the load limit. As load limits further increase once the shunt capacitors are switched in operationally, it is likely that transmission assets would reach their thermal limits long before the voltage stability limit is reached. PV curve analysis on selected 220 kV buses shows the system operator may not have the luxury of relying on reducing bus voltages as a warning sign for incipient voltage collapse. Analysis of the PV curve nose point also shows the critical voltage at the point of voltage collapse for all 220 kV buses remains above the obligations in the Code. QV curve analysis on selected 220 kV buses shows the system has a suitable margin of reactive reserve to withstand the most limiting contingencies defined for those regions. From the analysis conducted within this section it is believed the uptake of large amounts of PV generation will not adversely affect voltage stability on the transmission system.

7 KEY FINDINGS AND CONCLUSIONS 7.1 Voltage management during light load The voltage management study assumed all PV generation to be generated from roof-top PV technology, supplying power at the demand side. Grid connected solar farms and energy storage were not considered. The study showed the penetration of PV generation would introduce two negative effects on power system operation: • Displacement of synchronous generation connected at the transmission system • Reduction of system net load, resulting in less electrical power-flowing through the transmission system A lightly loaded transmission system would experience high voltages requiring reactive power regulating devices to absorb excess reactive power generated by the transmission system. This showed that displacement of grid connected synchronous generation would put pressure on critical reliability (ancillary) services, presenting challenges for managing voltage regulation during periods of high PV generation. This was particularly so with PV generation approaching 3000 MW during the summer period. Displacement of grid connected synchronous generation would leave the power system with reduced connected synchronous generation to maintain steady state voltage stability. This would create a challenging situation for the system operator to manage voltages in the transmission system during steady state operation. At midday in winter, demand is higher than summer, requiring more synchronous generation to be dispatched to meet net demand. In this scenario, the power system is secure, with high voltages able to be managed during steady state operation and following contingency events. Under both summer and winter scenarios, all shunt capacitor banks in the power system would need to be switch out of service to contain system voltages within the statutory limit, except for the Hayward and Benmore filters (which support HVDC operations). Thermal generating units in Taranaki region are vital power system components in managing system voltages in this region by absorbing excess reactive power generated by lightly load transmission circuits. If the generating units are offline during peak PV generation, the region experience high voltages. In this scenario, switching out the 220 kV circuits would mitigate the high voltage issue. At PV generation above 2000MW, it may mean the current practice of removing circuits for high voltage management at night will be required during the day. If so, prudent system co-ordination will be required to manage PV generation ramp up, while managing load ramp and switching circuits in/out for voltage management. With high PV generation in the mix the existing operational issues are amplified.

The reduced voltage regulation capability caused by high PV generation leads to challenges in managing system voltage during normal operation and following a contingency. Contingencies such as disconnection of Kikiwa STATCOM and Albany SVC will result in high voltages in the surrounding area.

7.2 Effect on fault levels The study showed that the greatest decrease in fault level occur at the 220 kV buses in Grid Zone 4 and Grid Zone 13 where synchronous generation was displaced by PV generation. The Auckland 220 kV network was least affected as there is very little synchronous generation available for dispatch in the region. Only Huntly 220 kV buses at the boundary of Auckland region showed the decrease in fault current when the thermal generating units are dispatched offline as PV generation increases. In general, system strength11 increased in the lower voltage level network as PV generation increased. This shows that shifting system strength from the 220 kV voltage network to the lower voltage network is more noticeable in high PV penetration regions such as Northland, Auckland and Nelson. These regions have very little synchronous generation, relying mainly on capacitor banks and SVC/STATCOM to support voltage. In this study, the reduction in system strength did not cause significant deterioration in this performance but only marginally increased the voltage step size when PV generation reached 3000 MW.

7.3 PV generation voltage ride through capability It is important to maintain the connection of all the power system equipment, other than the faulted one, to provide the power system the best chance to recover from an event. Therefore, the ability of the equipment to ride through a fault or event is important to avoid cascade failure and wide spread disturbance. AS/NZS 4777.2:2015 prescribes voltage ride through and anti-islanding protection requirements for PV generation during and after a voltage depression caused by a system fault. This requirement was incorporated into the PV generation model used in this study. The study showed that with PV generation approaching 1750 MW during winter, the amount of PV generation disconnected exceeds the system CE risk, implying that the system frequency would drop below the 48 HZ limit if a CE contingency occurred. As PV generation increases, the amount of PV generation unable to ride through a voltage event will also increase and increased disconnection during a power system event would exceed the system ECE risk when PV generation reached 2900 MW during summer. Additional frequency reserve is required to manage this system risk to avoid cascade failure.

11 See subsection 5.2.1 for definition.

PV generation is geographically dispersed, making it difficult to determine the risk magnitude and, consequently setting challenges to procuring adequate frequency reserve.

7.4 Effect on voltage stability Generation of real power stemming from PV connected at lower voltage level buses within distribution networks will essentially net off load within that region, thereby reducing reliance on meeting demand from remote generation delivered via the transmission system. The effect is a lightly loaded transmission system that requires capacitor banks and transmission circuits to be switched out of service to manage over- voltages. The study highlighted adequate voltage stability margin to supply demand in upper North Island and upper South Island with PV generation up to 3000 MW.

7.5 Study limitations The results of this study should be considered in the context of the limitations present in the adopted methodology. These limitations generally relate to the assumptions made, i.e. the information available to create network and component models and the real- world conditions that cannot be adequately factored into the analysis. Some of the limitations are: • The generation dispatched is derived from SPD solves that assume the amount of net free reserve (NFR) available in the system. This was considered to be reasonably accurate and adequate for this type of study. • There is limited solar inverter dynamic behaviour information available to create an accurate inverter model. The inverter models were created based on benchmark testing performed on 3 different inverter types. • The proportion of total PV generation assigned to each inverter type was based on manufacturer market share data in other countries. • The distribution networks’ voltage management strategies are unknown and were not factored into the study. • Distribution networks were modelled as lumped equivalent impedance connected at the GXPs (see subsection 3.1). The effect of distribution voltage rising due to lightly loaded distribution network was not considered. • PV generators were configured to operate with no voltage control and at unity power factor prior to a contingency. • All PV generation output was materialised at the grid level; that is, there was no curtailment due to power quality issues or low-voltage feeder congestion, or loss of output due to local shading of PV panels. • All PV generation was treated as if located at the NIWA measurement site used for each region's solar profile. Realistically, the aggregate curve would be spread wider with additional fluctuations due to geographic diversity and clustering of solar PV sites.

• All PV generation was derived from solar irradiance data recorded from a limited number of weather stations. Realistically, the PV generation would be less correlated between GXPs, thus making the national PV generation profile likely to be smoother. • Energy storage and demand side management were not considered. In practice, these might be used to help mitigate the impacts of the high PV penetration. The main consequence of these limitations is that the study results are more conservative than the likely real-world conditions. Other factors that can affect the study results are: • Severe weather fronts or solar eclipses affecting the variability of PV generation • PV generation not having voltage control capability at steady state • Distribution network capacity limiting the amount of PV generation that can be exported to the grid • PV generation performance not complying with AS/NZS 4777.2.2015 in riding through frequency and voltage disturbances

8 RECOMMENDATIONS

The New Zealand power system can accommodate a significant amount of PV generation before encountering challenges to managing system voltage. However, it is considered prudent to continue to improve our capability and operational tools in readiness for changes in power system characteristics and dynamic behaviour resulting from increasing PV generation.

8.1 Voltage management strategy The existing voltage management practices (which are used to manage high voltages during the existing night time load trough) to manage high voltages caused by the midday net PV-load trough are adequate for less than 2000 MW PV generation. Practices include switching out transmission circuits and running hydro generating units in Tail Water Depress mode can be utilised to manage system voltages. The uptake of PV generation in New Zealand should be actively monitored and, when approaching 2000 MW installed PV, the adequacy of the system operator’s voltage management practises should be monitored.

8.2 Inverter standard There needs to be active participation in the industry conversation already occurring between distribution companies and PV manufacturers to ensure that PV inverters conform to the AS/NZS 4777.2:2015 standard, particularly in the areas of voltage ride through and reactive power provision. Compliance with AS/NZS 4777.2:2015 will enable the system operator to adequately predict PV generation behaviour for secure operation. When PV generation penetration increases to a level that can impact the security of supply, it is essential that all installed PV inverters operate to the same standard as grid-connected synchronous generators. Compliance with this standard should be made now to avoid the accumulation of large PV generation blocks the behaviour of which cannot be relied upon during faults and under/over-voltages.

8.3 Collaboration with distribution network operators Transpower needs to work collaboratively with distribution network operators in the following areas: • Enhance the system operator’s demand forecasting (both active and reactive power) of high PV penetration distribution feeders. The assumption that GXP load follows the standard load profile will become progressively invalid with increasing levels of PV generation and other emerging technologies embedded in the distribution network. • Share voltage management strategies as installed PV levels increase enabling a coordinated voltage management approach for the New Zealand power system

• Investigate obtaining visibility of important operation parameters at critical nodes within the distribution network to assist the system operator with transmission system operation

8.4 Long term planning Strategic Planning should include grid strategies that enable the power system to operate with highly variable demand and generation, delivering active power during maximum demand periods and operating securely during extreme light demand periods. This PV generation voltage management investigation indicates that increasing PV penetration will result in greater extremes between trough and peak system demand becoming a feature of the future power system.

A1 POWER-FLOW SUMMARY BY GRID ZONE

This section provides a summary of the power-flows used in the light load high voltage management study. Table 3: below shows the summary of the winter 3150 MW (13:00) power-flow.

Table 3: winter 3150 MW (13:00) power-flow summary

Grid Zone Gen MW Gen MVAr Load MW Load MVAr PV MW NOR Grid 20 -96 538 67 470 Zone 1 NOR Grid 45 -8 1008 193 837 Zone 2 NOR Grid 160 -23 477 106 255 Zone 3 NOR Grid 533 -69 335 57 216 Zone 4 NOR Grid 0 0 228 25 97 Zone 5 NOR Grid 30 -7 166 39 89 Zone 6 NOR Grid 191 -44 204 27 146 Zone 7 NOR Grid 139 -182 410 53 335 Zone 8 SOU Grid 14 -24 166 20 120 Zone 9 SOU Grid 0 79 341 97 230 Zone 10 SOU Grid 18 12 195 65 106 Zone 11 SOU Grid 20 -4 31 5 31 Zone 12 SOU Grid 487 -176 111 22 70 Zone 13 SOU Grid 347 93 849 253 136 Zone 14 TOTAL 2002 -450 5059 1031 3137

Table 4 below shows the summary of the summer 3000 MW (16:00) power-flow.

Table 4: summer 3000 MW (16:00) power-flow summary

Grid Zone Gen MW Gen MVAr Load MW Load MVAr PV MW NOR Grid 23 -114 415 70 424 Zone 1 NOR Grid 45 -69 729 133 753 Zone 2 NOR Grid 142 -44 418 112 241 Zone 3 NOR Grid 217 -120 301 63 206 Zone 4 NOR Grid 0 0 236 36 89 Zone 5 NOR Grid 56 -28 162 51 88 Zone 6 NOR Grid 39 -20 201 56 144 Zone 7 NOR Grid 0 -180 285 26 335 Zone 8 SOU Grid 14 -8 134 31 118 Zone 9 SOU Grid 0 -64 280 69 247 Zone 10 SOU Grid 24 -2 273 63 114 Zone 11 SOU Grid 20 -1 64 16 32 Zone 12 SOU Grid 464 -129 142 22 74 Zone 13 SOU Grid 438 -19 789 282 144 Zone 14 TOTAL 1482 -798 4431 1031 3008

Table 5 shows the summary of the summer 3350 MW (12:00) power-flow.

Table 5 summer 10/01/2016 11:00 power-flow summary

Grid Zone Gen MW Gen MVAr Load MW Load MVAr PV MW NOR Grid 24 -183 437 46 479 Zone 1 NOR Grid 33 -72 764 160 855 Zone 2 NOR Grid 33 -4 410 84 274 Zone 3 NOR Grid 113 -75 321 65 234 Zone 4 NOR Grid 0 0 237 41 104 Zone 5 NOR Grid 9 -30 139 38 97 Zone 6 NOR Grid 0 0 163 42 160 Zone 7 NOR Grid 0 -265 308 29 375 Zone 8 SOU Grid 12 -24 143 24 129 Zone 9 SOU Grid 0 -50 286 58 270 Zone 10 SOU Grid 46 -9 260 66 124 Zone 11 SOU Grid 16 4 53 11 34 Zone 12 SOU Grid 470 -74 139 17 79 Zone 13 SOU Grid 401 146 791 279 151 Zone 14 TOTAL 1155 -636 4450 959 3364

A2 FAULT LEVEL AND VOLTAGE STEP INFORMATION A2.1 System strength and equivalent system impedance A strong power system will have smaller voltage fluctuations than a weaker one. The underlying characteristic determining this system strength and resultant voltage fluctuations is the equivalent impedance of the power system. A weaker power system has a higher equivalent impedance and will consequently experience greater voltage steps during faults and switching events than a stronger system, which has a lower equivalent impedance. The equivalent power system impedance is defined as the equivalent impedance of the transmission system combined with the internal reactance of all generating units that are online (i.e. the generator circuit breakers are closed) at the time of the fault and other connected equipment such as shunt capacitors, SVCs, STATCOMs. See Figure 47. V=1.0pu

Load Xequivalent

Figure 47: The equivalent impedance includes the transmission system impedance, and any other impedances such as shunt capacitors and internal reactances of all online generating units This underlying equivalent system impedance changes when the grid changes (e.g. closing a system split, or generating units are dispatched on/off the system). If the voltage step increases from before to after a grid change, then the underlying impedance has increased and the system is weaker. Figure 23 illustrates a steady-state voltage step before and after a change in the grid.

A2.2 Short-circuit current and equivalent system impedance In addition to voltage step, changes in short-circuit (aka. fault) current can also be used to assess system strength. Fault currents are easier to calculate than voltage steps (refer the next two sections). Therefore, they are preferred as the measure for initially identifying weaker areas of the grid. Then voltage steps can be calculated for specific buses. Generation is the primary source of fault current. During a fault, the short-circuit current flows from these generation sources to the fault location, through the equivalent impedance of the power system. In general terms, the amount of current contributed by each generating unit into a faulted point is determined primarily by the internal voltage and reactance of that generating unit, any current-limiting protection, and the equivalent impedance of the

transmission system between the generator’s terminals and the fault. The fault current is not significantly affected by the amount of MW generated by the unit. As generating units come online the total fault current increases, indicating that the underlying equivalent power system impedance has decreased. This in turn indicates that we have a stronger system and can expect smaller voltage fluctuations during switching events and contingencies. Similarly, as generating units go offline, the total fault current decreases due to an increase in the underlying equivalent power system impedance, which in turn indicates that the system has become weaker and that larger voltage fluctuations can be expected during planned events and contingencies.

A2.3 Technical background – fault level analysis Two fault level calculation methods were used to determine how the increase in PV generation affects system strength and voltage management at a national level and then at a regional level: 1. Analytical spreadsheet analysis using fault level formulae and the generator dispatch status table to provide a national view. 2. Steady-state power-flow analysis using commercial software to study the influence of PV penetration on fault currents at individual buses. In the analytical spreadsheet analysis approach the approximate maximum fault level that every generating unit can supply was calculated using the following formula:

I = (kA)

Srated ( ) fault √3 Xgenerator Vrated line−to−line Xgenerator is the subtransient reactance (X”d). A generator dispatch status table was also utilised. The table identifies the generators in and out of service for each power-flow scenario. Generator dispatch statuses were produced using an SPD bid and offer stack for a typical wet year (refer subsection 3.3). See Appendix A2.5 for a sample of the dispatch status table. Using these two data sets, the change in total maximum fault level for each island can be observed as generating units come in/out of service from 0 MW to 3100 MW (see Figure 24 and Figure 26. In the steady-state power-flow approach the following method was applied to each scenario: 1. A three-phase, zero impedance bus fault12 was applied to every 220 kV and 110 kV bus in the Transpower network using the classical fault calculation method. 2. The short-circuit current was recorded for every faulted bus.

12 A three-phase, zero impedance bus fault is when all three phases of a substation bus (e.g. 220 kV, 110 kV, 33 kV bus) have been unintentionally connected directly to ground (i.e. 0 kV) through a zero impedance short-circuit.

A spreadsheet table of short-circuit currents across all scenarios was then compiled to observe how they change as the PV generation increases from 0 MW to 3100 MW. The generator maximum fault levels from the analytical approach are higher than those calculated using the power-flow approach. The analytical approach calculates the maximum fault level that each generating unit can supply into the system at the generator’s terminal bus, based on the unit’s internal reactance. It uses rated voltages and ignores the equivalent impedance of the transmission system. This differs from the fault current contribution of each unit to a fault at a remote load bus, which the power- flow software calculates; each contribution is a function of the equivalent network impedance as well as the internal generator reactance.

A2.4 Technical background – voltage step analysis The goal of this voltage step analysis was to calculate the change in each bus’s voltage step from one scenario to the next, reflecting regional changes in system strength caused by increasing PV generation levels. The voltage step is the magnitude of the transient voltage occurring in the first one to two cycles after a routine operational event. Specialised switching studies were used to calculate these transient voltage steps. Instead of needing to build and run full dynamic simulations, the switching study process obtains these voltage step values by converting the standard power-flow case into a matrix of voltages and impedances reflecting the state of generators and other network components in the milliseconds after the event. Once the voltage steps (in %) were calculated, the following ‘rule of thumb’ formulae were used to sanity-check these voltage steps. X = (pu) ( ) 1 equivalent Sshort −circuit⁄Sbase V = 100 X (%)

where: step ∙ equivalent

• Xequivalent is the equivalent short-circuit impedance of the power system, ignoring resistance.

• Sshort-circuit is the short-circuit power calculated in subsection 5.3.3.1 using power- flow software

• Sbase = 100 MVA

A2.5 Generator dispatch status table Table 6 below contains a sample of the synchronous generator dispatch statuses used in the analytical spreadsheet analysis performed on the winter Tuesday scenarios. The statuses of all 374 solar PV units were “Out” for 0 MW, 07:00, scenario and “In” for scenarios 750 MW to 3100 MW.

These generator dispatch statuses were used to calculate the total fault levels in subsection 5.3. They also explain why some Grid Zone s experience greater decreases in fault level (and hence decrease in system strength) than other regions. Specifically, as more generating units come out of service the system weakens.

Table 6: A sample of synchronous generating unit dispatch statuses used in the analysis of winter Tuesday scenarios

Generator Grid Equipment 0 MW 750 MW 1100 MW 2050 MW 2650 MW 3100 MW Zone Name 07:00 08:00 08:20 09:35 10:30 12:00 3 ARI G1 In In In In In In 3 ARI G2 In In In Out Out Out 3 ARI G3 Out Out Out Out Out Out 3 ARI G4 Out Out Out Out Out Out 3 ARI G5 In In In In In In 3 ARI G6 In In In In In Out 3 ARI G7 In In In Out Out Out 3 ARI G8 In In In Out Out Out 4 WKM G1 In In In In Out Out 4 WKM G2 In In In Out Out Out 4 WKM G3 In In In Out Out Out 4 WKM G4 In In In Out Out Out 13 BEN G1 In In In In In In 13 BEN G2 In In In In In In 13 BEN G3 In In In Out Out Out 13 BEN G4 In In Out Out Out Out 13 BEN G5 In In Out Out Out Out 13 BEN G6 Out Out Out Out Out Out

A2.6 Fault current change maps The maps on the following pages help visualise the changes in fault currents as synchronous generating units are displaced by PV generation. These results are described fully in subsection 5.3.3.1. Decreases in fault current are caused generating units coming out of service, which can be seen in the generator dispatch status Table 6 shown above. Note: Change maps are not included for the 1100 MW (08:20) scenario because they are identical to the 750 MW (08:00) maps. The change in fault current from 750 MW to 1100 MW is too small to be observed.

Figure 48: Change in fault currents from PV 0 MW to 750 MW – 220 kV network Figure 49: Change in fault currents from PV 0 MW to 3100 MW – 220 kV network

Figure 50: Zoom on Grid Zone 1-4. Change in fault currents Figure 52: Zoom on Grid Zone 1-4. Change in fault currents from PV 0 MW to 750 MW – 220 kV network from PV 0 MW to 2050 MW – 220 kV network

Figure 51: Zoom on Grid Zone 1-4. Change in fault currents Figure 53: Zoom on Grid Zone 1-4. Change in fault currents from PV 0 MW to 2650 MW – 220 kV network from PV 0 MW to 3100 MW – 220 kV network

Figure 54: Change in fault currents from PV 0 MW to 750 MW – 110 kV network Figure 55: Change in fault currents from PV 0 MW to 3100 MW – 110 kV network

Figure 56: Zoom on Grid Zone 1-4. Change in fault currents Figure 58: Zoom on Grid Zone 1-4. Change in fault currents from PV 0 MW to 750 MW – 110 kV network from PV 0 MW to 2050 MW – 110 kV network

Figure 57: Zoom on Grid Zone 1-4. Change in fault currents Figure 59: Zoom on Grid Zone 1-4. Change in fault currents from PV 0 MW to 2650 MW – 110 kV network from PV 0 MW to 3100 MW – 110 kV network

A3 INVERTER MODELS

The inverter models used in this study were produced based on the testing of 3 inverters, looking at 4 key characteristics: 1. Active power control/frequency response 2. Reactive power control/voltage response 3. Frequency/voltage ride through capability 4. Reconnect characteristics The inverters displayed different characteristics for frequency response and fault ride through capability. All three inverters had variable settings for voltage response, with key selectable modes being volt-var mode, and constant power factor mode. A total of six inverter model types were produced for this analysis. That is, the three tested inverters were each modelled with a volt-var mode setting and with a constant power factor mode setting. Table 7 below shows a summary of the characteristics of the 6 inverter types and the following section provides detail of the key characteristics of the models for the 3 inverters, Inverter A, B and C.

Table 7: Summary of Inverter model characteristics

Inverter Under- Over-Frequency Voltage Reconnect Type Frequency Response Control Characteristic response Mode Type 1 - None Yes, 0.2 Hz deadband Volt-Var Ramp, 90s reset time Inverter A Type 2 - None Yes, 0.2 Hz deadband Constant Ramp, 90s reset time Inverter A Power factor Type 3 - None None Volt-Var Step, 50s reset time Inverter B Type 4 - None None Constant Step, 50s reset time Inverter B Power factor Type 5 - None Yes, 1 Hz deadband Volt-Var Step, 20s reset time Inverter C Type 6 - None Yes, 1 Hz deadband Constant Step, 20s reset time Inverter C Power factor

A3.1 Active power/frequency control Inverter A, B and C exhibit different active power/frequency control characteristics, with neither displaying under-frequency response. Inverter A showed over-frequency response with a deadband of 0.2 Hz, and approximately 2.6% droop. Inverter B showed no over-frequency response. Inverter C showed over-frequency response with a deadband of 1 Hz, and approximately 5% droop. The inverter displayed a rapid ramp back to maximum power output once the frequency returned to within 51 Hz. Figure 60 below shows the over-frequency response of the three inverter types. Figure 61 shows the block diagram for the active power component of the Inverter C dynamic model. Inverter A and B are similar, but no ramp back characteristic and different droop, gains and deadband settings.

Figure 60: solar PV Inverter Over-Frequency Response

Figure 61: Frequency Control component of Inverter C Dynamic Model

A3.2 Reactive power/voltage control All three tested inverters have selectable voltage control modes. The behaviour of the inverters in each mode varied between inverter types, however to simplify modelling requirements 2 control modes have been applied to all 3 inverters; volt-var mode and constant power factor mode. Both control modes have been modelled based on Inverter A response. The inverters have been modelled with a 33% limit on reactive power, as per the Inverter A tested value. The volt-var characteristic has a deadband and droop, with asymmetric settings for over and under-voltage response. The constant powerfactor characteristic has been modelled controlling the reactive power based on the active power output to maintain constant power factor. Due to the assumption of 0 MVAr output in the power-flow, this mode essentially equates to no voltage response in this study. Figure 62 and Figure 63 show the simulated response of the volt-var and constant power factor models. Figure 64 and Figure 65 show the block diagram for the volt-var and constant power factor component of the dynamic models.

Figure 62: solar PV Inverter Volt-Var Response to voltage step

Figure 63: solar PV Inverter Constant Powerfactor Response to over-frequency event

Figure 64: Volt-Var component of Inverter Dynamic Model

Figure 65: Constant Power Factor component of Inverter Dynamic Model

A3.3 Voltage/Frequency ride through Inverters A, B and C displayed different characteristics when tested for voltage and frequency ride through. Inverter B is most resilient to under-voltage, with tests showing it remaining connected at 10 V (0.043 pu) for 1 second. Inverter C has an instantaneous under-voltage trip at 160 V (0.696 pu), and Inverter A will trip at 45 V (0.195 pu) for 10ms. All inverters are able to ride through most frequency events which can be expected in the New Zealand power system. Inverter B and C may trip in a South Island over-frequency event assisting in the arrest of over-frequency. Inverter C may trip for a South Island extended contingent event (ECE) as the frequency could potentially fall to 45 Hz. Due to the requirement to also model inverter reconnecting characteristics, the voltage and frequency "trips" have been modelled as limiters on the active and reactive power control blocks, rather than disconnections of the model from the simulation. Figure 66 shows the block diagram for the frequency and voltage trip and reconnect component of Inverter C, and the interface to Pmax and Qmax. Inverter A and B have the same structure, with settings according to Table 6.

Table 8: Inverter voltage and frequency ride trip settings

Inverter Type Voltage Frequency Vup1 TVup1 Vup2 TVup2 Vdown1 TVdown1 Vdown2 TVdown2 Fup TFup Fdown TFdown (pu) (s) (pu) (s) (pu) (s) (pu) (s) (Hz) (s) (Hz) (s) Inverter A 1.217 0.01 1.174 2 0.78 2 0.74 1 55 0 45 0.01 Inverter B 1.152 0.2 1.122 2 0.78 2 53 0.2 45 0.1 Inverter C 1.148 2 0.78 2 0.696 0 53 0.2 47 2

Figure 66: Voltage and Frequency trip and reconnect component of Inverter C Dynamic Model

A3.4 Reconnect characteristics Inverters A, B and C displayed different reconnect characteristics following a frequency or voltage trip. The reconnection was characterised by the reset time and rate at which the inverter returns to maximum power output. Inverter A had a reset time of 90s, and returned to maximum power output with a slow ramp for the first 50% over approximately 50s, then a fast ramp for the remaining 50% over approximately 5s. This was approximated in the model as a ramp to maximum power output over about 40s. Inverter B had a reset time of 50s and reconnected with a step to maximum power output. Inverter C had a reset time of 30s and reconnected with a step to maximum power output. Figure 66 above shows the block diagram for the frequency and voltage trip and reconnect component of Inverter C, and the interface to Pmax and Qmax.

A3.5 Inverter type distribution Each inverter type was distributed across the PV inverter models to give an active power generation proportion based on the market share of the tested inverters in the U.S13. In 2014, the three tested inverters accounted for 41% of the total market share in 2014. Extrapolating their relative market shares to 100%, gives:

Inverter A: 17% Inverter B: 71% Inverter C: 12% These three inverter market shares were further divided into reactive power control settings (volt-var mode and power factor mode) and applied to the PV distribution in the power-flow scenarios. The approximate proportions across New Zealand are given in Table 9. The inverter types are linked to lumped representations of PV generation in the power-flow. The actual distribution of PV generation will vary across different power- flows used with different solar irradiance conditions throughout the day.

Table 9: solar PV Inverter model New Zealand proportion

Inverter Type Proportion of Total PV MW Type 1 - Inverter A 8.6% Type 2 - Inverter A 8.3% Type 3 - Inverter B 34.2% Type 4 - Inverter B 37.0% Type 5 - Inverter C 5.4% Type 6 - Inverter C 6.6%

13 https://www.greentechmedia.com/articles/read/who-is-leading-the-u.s.-residential-inverter-market

A4 VOLTAGE STABILITY STUDY RESULTS

This appendix explains voltage stability as it relates to the New Zealand power system.. A and full listing of results from the voltage stability studies is also provided here. Conventional power systems are highly radial with grid scale synchronous generation as the source and consumer load as the sink. This would traditionally form a one- dimensional transmission corridor of power from generation to load and is typical of what would be seen in most traditional power systems going back in history. However, with an increase in small-scale distributed generation such as solar PV, this can have a marked effect on New Zealand’s power system. The action of generator and reactive compensation device AVRs, provide the most important source of voltage control. Under normal conditions, the terminal voltages are maintained constant. During low system voltages, the generators can increase their reactive power output in order to increase system voltage. A4.1 Voltage stability explained

Voltage stability is one of the classifications of power system stability. Power system stability is defined as the characteristics of a power system to remain in a state of equilibrium at normal operating conditions and to restore an acceptable state of equilibrium after a disturbance [5]. Power systems have a finite supply capability, once this supply capability is reached voltage instability ensues. Increasing intra-regional power transfers in the system from remote generation to load centres can cause voltage depression in the receiving region. More seriously, extremely high levels of power transfer or extreme contingencies could lead to a voltage collapse in the load centre. This can ultimately result in what is often called a “blackout”, due to insufficient reactive power support in a system. Voltage collapse is a manifestation of voltage instability in the system. The definition of voltage stability as proposed by IEEE/CIGRE task force is as follows [5]: Voltage stability refers to the ability of power system to maintain steady voltages at all buses in the system after being subjected to a disturbance from a given initial operating point. The system state enters the voltage instability region when a disturbance or an increase in load demand or alteration in system state results in an uncontrollable and continuous drop in system voltage.

Static security analysis conducted in this section falls under a classification of power system stability as illustrated in Figure 67. The analysis is power-flow based and conducted as quasi-static voltage stability studies. This is where reactive compensation devices were allowed to adjust in response to a disturbance, however discrete shunts and ULTCs were fixed.

Figure 67: Classification of Power System Stability [5] This study involves steady state analysis of post-disturbance system conditions to verify that no equipment ratings or voltage constraints are violated. Large-disturbances being system faults, loss of generation, loss of reactive compensation devices or circuit contingencies.

A4.1.1 Factors influencing voltage instability Voltage instability may arise due to many reasons, but some significant contributors are: • Large distances between generation and load • Increase in transmission circuit loading • Unfavourable load characteristics • Generators, synchronous condensers, or reactive power compensation devices reaching their respective limits • Tapping action of ULTCs on transformers • Poor coordination between various control and protective systems • Extreme contingencies (e.g. line tripping or generator outages) • HVDC link bipole trip Most of these changes have a significant impact on the reactive power production, transmission and consumption in the system. Some counter measures to prevent voltage collapse are: • Switching of shunt capacitors • Blocking of tapping action on transformers with automatic ULTCs • Re-dispatch of generation • Load shedding schemes, such as AUVLS or Demand Response

• Temporary reactive power overloading of generators • Reactive power compensation (e.g. SVC, STATCOM)

A4.1.2 Determination of voltage stability limit Two common methods that are available to determine voltage stability are PV curves and QV curves. The PV curve is presented in Figure 68, which illustrates the voltage on a load bus as a function of real power demand or sum of load demand.

Figure 68: PV Curve [6] PV curve computation is analysed to determine the stability margin of the system (with respect to realistic stresses, not an artificial reactive stress at one bus alone) and identifying the weak buses and voltage collapse regions for each contingency. For a particular demand, two voltage solutions are obtained. These are low current – high voltage (stable region) and high current – low voltage (unstable region) solutions. Power systems are operated in the upper part of the PV-curve, that is, the low current – high voltage solution. This part of PV-curve is statically and dynamically stable. The nose point of the curve is also commonly called the maximum loading point. The critical point where the solutions coincide is the voltage collapse point. The QV curve is presented in Figure 69, which illustrates the reactive power injection as a function of voltage on a load bus.

Figure 69: QV Curve [7]

QV curve computation is one of the earlier methods of voltage stability analysis and can also be used to determine the stability of the system. In addition to showing the sensitivity of the bus voltage to reactive power injection (or reactive load) at that bus, the curve shows the reactive power margin at that bus, which is how much the system can be stressed by reactive load increase at that one bus before it becomes “unstable”.

A4.1.3 Definitions Transpower is obligated to maintain 0.9 pu voltage under N-1 conditions under the Asset Owner Performance Obligations defined by of Part 8 of the Electricity Industry Participation Code. The PV curve is analysed to determine if the critical voltage of 220 kV buses remain above the voltage limits specified in the AOPOs. In any case, Transpower maintains a load margin (security margin) of 5%. The voltage stability limit for the upper North Island and upper South Island regions is defined as the maximum pre-contingency real power that can be transferred into the respective region to avoid voltage collapse after the loss of a key power system component [8]. Note that the voltage stability transfer limit ignores all assets overloading in the rest of the island in which the respective study region is located. Voltage stability is limited by the first bus where voltage collapse occurs.

A4.1.4 Existing voltage stability management practices Over the course of a day the load profile within regions of the power system can change dramatically. As such this presents a quasi-static change on the voltage over time whereby voltage changes in a matter of tens of minutes or hours. This effect on voltage is further exacerbated by either planned or short-notice outages of equipment or system emergency events. The New Zealand power system is split up into major regional centres called Grid Zone s (Grid Zone ) – see the maps in subsection A2.6 . The system operator monitors these regional centres for Voltage Security of a given base operating point as well as security limits of a one dimensional power transfer. The regions/interfaces the system operator currently monitors in real-time are: • Zone 1 (Upper North Island comprising Grid Zone 1 – 2) • Zone 3 (Upper South Island comprising Grid Zone 9 – 12) • Grid Zone 1 • Grid Zone 5 • Grid Zone 6 – 8 • Grid Zone 9 • Grid Zone 12 • Grid Zone 14

Transpower’s management of voltage stability in real-time is achieved through interfacing a Powertech designed software called Voltage Security Assessment Tool (VSAT) to the real-time measurements and signals received through Supervisory Control and Data Acquisition (SCADA) software. The VSAT software and its computation process is explained in more detail in subsection A4.1.4.1. The outputs from VSAT are used as a pre-contingency measure by the system co- ordinators to determine if remedial action is required to maintain system security. VSAT will monitor the interfaces mentioned above and identify if there are any violations. These are: • Voltage Stability Margin Violation • Voltage Collapse • Reached Max/Min Voltage If these violations are seen, the system operator will take corrective actions to maintain system security. These corrective actions may include: • Increasing output of reactive compensation devices for voltage support • Using discretion to bring on additional generation and adjust generation MW • Altering of a security stability constraint • Arming of Automatic Under-Voltage Load Shedding (AUVLS) schemes • Issuing a Warning Notice to industry advising of an emerging issue • Issuing a Grid Emergency Notice advising of immediate action required • Demand Management to maintain N security

A4.1.4.1 VSAT voltage security explained VSAT has been designed by Powertech for both off-line (planning and operational planning studies) as well as on-line use (connected directly to an energy management system and enabled to automatically assess voltage security using live system snapshots). VSAT is a state-of-the-art tool for the assessment of power system voltage security. VSAT includes a number of specialized analytical techniques designed to permit the efficient analysis of large complex power systems. With VSAT, the user can specify a large number of scenarios which will be automatically analysed to provide such information as the critical contingencies and voltage security limits. VSAT takes regions or interfaces specified by the user within the power system as a 2 bus system representation as shown in Figure 70. Whereby the source is all generation available outside of the specified region and the sink is all load minus generation within the specified region.

Source Sink (Generation) (Load)

Interface

Figure 70: Two-Bus representation of Power System A brief overview of the computation process is explained below. Step 1: Scenarios are created in which the regions/interfaces to be studied are specified Step 2: Contingencies are specified to be applied in the security assessment (this can include generators, transformers, lines, reactive compensation devices etc.) Step 3: Security assessment solves the power-flow for the base point (pre-contingency) and for each of the contingencies specified in Step 2. Step 4: Transfer limits are computed. For this, the operating point is moved with a specified step size in the direction of the Transfer until the security limit is reached. VSAT ramps the load MW up at specified intervals, in this case 5% intervals with a lagging power factor of 0.98, then will re-dispatch connected generation to match the load. As illustrated in Figure 71, VSAT first takes a stable power-flow and applies the most limiting contingency to this power-flow to check whether the “N-1” state is stable. If stable, VSAT increases the power transfer by increasing both supply (Source) and demand (Sink) of MW on the “N” (pre-contingent system), checking the N-1 system is still stable. This process is iterated further until a maximum power transfer point is achieved for the N-1 system. The N/pre-contingent system is then limited to operate below the maximum power transfer as indicated by the N-1/post-contingent system. Transpower maintains a 5% margin on the calculated stability limit to form a security limit as defined in subsection A4.1.3.

Figure 71: VSAT's iterative technique for solving for voltage stability limits The power-flow does not converge if a pre or post-contingency case is solved during the security assessment in Step 2: that case is considered Voltage Unstable. The scenario is considered voltage secure if all the voltage criteria set in the criteria files are met - these criteria are usually an industry standard. The security criteria for this study are summarized in the following bullet points. • The system remains Voltage Stable (power-flow solution exists) in pre-contingency and all post-contingency conditions. • The system has the minimum specified margin to instability. This means the system remains Voltage Stable if it is stressed by the specified MW/MVAr amount of margin requirement. • Pre and post-contingency voltages are within specified limits. • Pre and post-contingency reactive operational limits of selected sources are larger than specified limits. A4.2 Interface MW transfer and voltage stability load limit results tabulation

The maximum load limits and values of generation can be found in Table 10 to Table 13 along with the most limiting contingencies for each power-flow. The values represented below take into account the 5% security margin requirement defined in appendix subsection A4.1.3.

Table 10: UNI post-contingency power-flow results – winter Scenario

Power-flow case Base case N.I. Max generation Base case load Max load limit Contingency (time of day) Gens (MW) (MW) (MW) (MW)

0700 1257 1599 1686 2028 HLY U5

0800 1277 1727 1862 2312 HLY U5

1100 553 1445 1596 2488 HLY_TWH 1

1200 341 1281 1575 2515 HLY_TWH 1

1300 239 1221 1546 2492 HLY_TWH 1

1400 307 1239 1523 2455 HLY_TWH 1

1600 818 1396 1626 2204 HLY_TWH 1

1700 1296 1742 1792 2238 OHW_WKM 1

1800 1548 1694 2011 2157 HLY U5

Table 11: USI post-contingency power-flow results – winter Scenario

Power-flow case Base case S.I. Max generation Base case load Max load limit Contingency (time of day) Gens (MW) (MW) (MW) (MW)

0700 2324 2629 796 1102 ISL_TKB

0800 2279 2519 967 1208 ISL_LIV

1100 898 1368 766 1237 ISL_LIV

1200 763 1273 739 1250 ISL_LIV

1300 763 1273 732 1242 ISL_LIV

1400 793 1308 734 1249 ISL_LIV

1600 1452 1852 778 1178 ISL_LIV

1700 1967 2302 834 1170 ISL_LIV

1800 2664 2904 913 1154 ISL_TKB

Table 12: UNI post-contingency power-flow results – summer Scenario

Power-flow case Base case N.I. Max generation Base case load Max load limit Contingency (time of day) Gens (MW) (MW) (MW) (MW)

0700 960 1760 980 1780 OHW_WKM 1

0800 490 1358 1194 2062 HLY_TWH 1

1100 128 1278 1209 2360 HLY_TWH 1

Table 13: UNI post-contingency power-flow results – summer Scenario

Power-flow case Base case S.I. Max generation Base case load Max load limit Contingency (time of day) Gens (MW) (MW) (MW) (MW)

0700 1071 1581 654 1164 ASB_TWZ 1

0800 783 1263 746 1227 ASB_TWZ 1

1100 704 1289 734 1320 ISL_LIV

A4.3 Contingency set used for voltage stability studies

The list of contingencies used within this study are listed below. These have been identified by the system operator as having potential impact on voltage stability within the upper North Island and upper South Island regions.

Table 14: List of contingencies with potential impact on voltage stability

Upper North Island Contingencies Upper South Island Contingencies

ALB_HEN1 HLY_OHW2 ASB_BRY1

ALB_HEN2 HLY_OTA2 ASB_ISL1

ALB_HEN3 HLY_SFD ASB_TWZ1

ARI_BOB1 HLY_TWH1 ASB_TWZ2

BOB_HAM1 KOE_MPE1 BRY_ISL

BOB_HAM2 KOE_MPE2 ISL_KIK1

BOB_OTA1 MDN_MPE1 ISL_KIK2

BOB_OTA2 MDN_MPE2 ISL_KIK3

DRY_OTA1 MNG_OTA1 ISL_LIV

HAM_OHW1 MNG_OTA2 ISL_SVC3

HAM_WKM1 MNG_ROS1 ISL_SVC9

HEN_HEP1 MNG_ROS2 ISL_TKB

HEN_HEP2 OHW_OTA1 KIKSTC2A

HEN_HEP3 OHW_OTA2 KIKSTC2B

HEN_HEP4 OHW_WKM1 KIK_T1

HEN_MPE1 OTA_PAK3 KIK_T2

HEN_MPE2 OTA_PAK4 STK_T7

HEP_ROS1 OTA_PEN5 TKB_TWZ

HEP_ROS2 OTA_PEN6

HLY1 OTA_ROS1

HLY2 OTA_ROS2

HLY5 OTA_WKM1

HLY_OHW1 OTA_WKM2

A4.4 Effect of PV generation on voltage stability for summer scenario

2500 1200.00

1000.00 2000 UNI PV Profile 800.00 1500

600.00

1000 400.00 UNI PV Profile (MW) PV Profile UNI and load profile load and (MW) 500 200.00 Voltage stabilityVoltage load limit, interface flow, 0 0.00 7:59 8:28 8:57 9:25 9:54 10:23 10:52 Time of day

UNI interface MW flow UNI voltage stability load limit UNI load profile

Figure 72: UNI region interface transfer flow and load limit changes with a rise in PV generation over the day – summer scenario

1600 600.00

1400 500.00 1200 USI PV Profile 400.00 1000

800 300.00

600 200.00 USI PV Profile (MW)

and load profile load and (MW) 400 100.00 200 Voltage stabilityVoltage load limit, interface flow, 0 0.00 7:59 8:28 8:57 9:25 9:54 10:23 10:52 Time of day

USI interface MW flow USI voltage stability load limit USI load profile

Figure 73: USI region interface transfer flow and load limit changes with a rise in PV generation over the day – summer scenario

1200

1000

800

600

400 Reactive Power (MVAr) Power Reactive 200

0 8:00 10:00 11:00 Time of day UNI equivalent line charging UNI shunt MVAr reserve (charging - losses in base case) (un-switched in base case)

Figure 74: UNI equivalent line charging and shunt MVAr reserve thought the day - summer scenario

700

600

500

400

300

200 Reactive Power (MVAr) Power Reactive

100

0 8:00 10:00 11:00 Time of day

USI equivalent line charging USI shunt MVAr reserve (charging - losses in base case) (un-switched in base case)

Figure 75: USI equivalent line charging and shunt MVAr reserve thought the day - summer scenario

A4.5 Effect of PV generation on transmission line loading for the summer scenario

100 3000.00

90 NIPS PV Profile 2500.00 80 11:00 70 2000.00 60

50 1500.00 PV Generation (MW) 40

Line loading (%) All UNI 1000.00 30 Island transmission 8:00 20 circuits KOE-MPE 1 & 2 500.00 North 10 7:00 0 0.00 6:28:48 AM 6:57:36 AM 7:26:24 AM 7:55:12 AM 8:24:00 AM 8:52:48 AM 9:21:36 AM 9:50:24 AM 10:19:12 AM 10:48:00 AM 11:16:48 AM Time of day Figure 76: Effect of solar PV on line loadings in UNI region for a summer Scenario

100 800.00

90 SIPS PV Profile 700.00 80 11:00 600.00 70 500.00 60

50 TIM-TKA 400.00 PV Generation (MW) 40 300.00 Line loading (%) All USI 30 Island transmission 8:00 200.00 20 circuits South 100.00 10 7:00 0 0.00 6:43:12 AM 7:12:00 AM 7:40:48 AM 8:09:36 AM 8:38:24 AM 9:07:12 AM 9:36:00 AM 10:04:48 AM 10:33:36 AM 11:02:24 AM Time of day Figure 77: Effect of solar PV on line loadings in USI region for a summer Scenario

A4.6 PV curves under pre-contingent conditions for winter and summer power-flow scenarios

1.04

1.035

1.03

1.025

1.02

1.015

1.01

1.005 Bus Voltage (pu) Voltage Bus 1

0.995

0.99

0.985 1680 1780 1880 1980 2080 2180 2280 2380 Load Limit (MW) 'ALB 220 131' 'BRB 220 21' 'DRY 220 2' 'GLN 220 15' 'HEN 220 28' 'HOB 220 210' 'HPI 220 1' 'MDN 220 21' 'OTA 220 153' 'OTA 220 56' 'PEN 220 32' 'SVL 220 1' 'SVL 220 12' 'SWN 220 10' 'TAK 220 2' 'TAK 220 4' 'WRD 220 8' Figure 78: PV curve of selected 220 kV buses in UNI region for pre-contingency winter 07:00 scenario

1.04

1.035

1.03

1.025

1.02

1.015

Bus Voltage (pu) Voltage Bus 1.01

1.005

0.995 1850 1950 2050 2150 2250 2350 2450 2550 2650 Load Limit (MW) 'ALB 220 131' 'BHL 220 1' 'BHL 220 2' 'BRB 220 21' 'DRY 220 2' 'GLN 220 15' 'HEN 220 28' 'HOB 220 210' 'HPI 220 1' 'MDN 220 21' 'OTA 220 153' 'OTA 220 56' 'PEN 220 32' 'SVL 220 1' 'SVL 220 12' 'SWN 220 10' 'TAK 220 2' 'TAK 220 4' 'WRD 220 8' Figure 79: PV curve of selected 220 kV buses in UNI region for pre-contingency winter 08:00 scenario

1.06

1.04

1.02

0.98 Bus Voltage (pu) Voltage Bus 0.96

0.94

0.92 1580 1780 1980 2180 2380 2580 2780 Load Limit (MW) 'ALB 220 131' 'BHL 220 1' 'BHL 220 2' 'BRB 220 21' 'DRY 220 2' 'GLN 220 15' 'HEN 220 28' 'HOB 220 210' 'HPI 220 1' 'MDN 220 21' 'OTA 220 153' 'OTA 220 56' 'PEN 220 32' 'SVL 220 1' 'SVL 220 12' 'SWN 220 10' 'TAK 220 2' 'TAK 220 4' 'WRD 220 8' Figure 80: PV curve of selected 220 kV buses in UNI region for pre-contingency winter 11:00 scenario

1.06

1.04

1.02

0.98 Bus Voltage (pu) Voltage Bus 0.96

0.94

0.92 1570 1770 1970 2170 2370 2570 2770 Load Limit (MW) 'ALB 220 131' 'BHL 220 1' 'BHL 220 2' 'BRB 220 21' 'DRY 220 2' 'GLN 220 15' 'HEN 220 28' 'HOB 220 210' 'HPI 220 1' 'MDN 220 21' 'OTA 220 153' 'OTA 220 56' 'PEN 220 32' 'SVL 220 1' 'SVL 220 12' 'SWN 220 10' 'TAK 220 2' 'TAK 220 4' 'WRD 220 8' Figure 81: PV curve of selected 220 kV buses in UNI region for pre-contingency winter 12:00 scenario

1.05

1.04

1.03

1.02

1.01

0.99

0.98 Bus Voltage (pu) Voltage Bus 0.97

0.96

0.95

0.94 1540 1740 1940 2140 2340 2540 2740 Load Limit (MW) ALB 220 'BHL 220 1' 'BHL 220 2' 'BRB 220 21' 'DRY 220 2' 'GLN 220 15' 'HEN 220 28' 'HOB 220 210' 'HPI 220 1' MDN 220 OTA 220 'OTA 220 56' 'PEN 220 32' 'SVL 220 1' 'SVL 220 12' 'SWN 220 10' 'TAK 220 2' 'TAK 220 4' 'WRD 220 8' Figure 82: PV curve of selected 220 kV buses in UNI region for pre-contingency winter 13:00 scenario

1.06

1.04

1.02

0.98 Bus Voltage (pu) Voltage Bus 0.96

0.94

0.92 1510 1710 1910 2110 2310 2510 2710 Load Limit (MW) 'ALB 220 131' 'BHL 220 1' 'BHL 220 2' 'BRB 220 21' 'DRY 220 2' 'GLN 220 15' 'HEN 220 28' 'HOB 220 210' 'HPI 220 1' 'MDN 220 21' 'OTA 220 153' 'OTA 220 56' 'PEN 220 32' 'SVL 220 1' 'SVL 220 12' 'SWN 220 10' 'TAK 220 2' 'TAK 220 4' 'WRD 220 8' Figure 83: PV curve of selected 220 kV buses in UNI region for pre-contingency winter 14:00 scenario

1.04

1.03

1.02

1.01

0.99 Bus Voltage (pu) Voltage Bus 0.98

0.97

0.96 1620 1720 1820 1920 2020 2120 2220 2320 2420 Load Limit (MW) 'ALB 220 131' 'BHL 220 1' 'BHL 220 2' 'BRB 220 21' 'DRY 220 2' 'GLN 220 15' 'HEN 220 28' 'HOB 220 210' 'HPI 220 1' 'MDN 220 21' 'OTA 220 153' 'OTA 220 56' 'PEN 220 32' 'SVL 220 1' 'SVL 220 12' 'SWN 220 10' 'TAK 220 2' 'TAK 220 4' 'WRD 220 8' Figure 84: PV curve of selected 220 kV buses in UNI region for pre-contingency winter 16:00 scenario

1.04

1.03

1.02

1.01

Bus Voltage (pu) Voltage Bus 1

0.99

0.98 1780 1880 1980 2080 2180 2280 2380 Load Limit (MW) 'ALB 220 131' 'BHL 220 1' 'BHL 220 2' 'BRB 220 21' 'DRY 220 2' 'GLN 220 15' 'HEN 220 28' 'HOB 220 210' 'HPI 220 1' 'MDN 220 21' 'OTA 220 153' 'OTA 220 56' 'PEN 220 32' 'SVL 220 1' 'SVL 220 12' 'SWN 220 10' 'TAK 220 2' 'TAK 220 4' 'WRD 220 8' Figure 85: PV curve of selected 220 kV buses in UNI region for pre-contingency winter 17:00 scenario

1.035

1.03

1.025

1.02

1.015

1.01 Bus Voltage (pu) Voltage Bus 1.005

0.995 2000 2050 2100 2150 2200 2250 2300 2350 2400 2450 Load Limit (MW) 'ALB 220 131' 'BHL 220 1' 'BHL 220 2' 'BRB 220 21' 'DRY 220 2' 'GLN 220 15' 'HEN 220 28' 'HOB 220 210' 'HPI 220 1' 'MDN 220 21' 'OTA 220 153' 'OTA 220 56' 'PEN 220 32' 'SVL 220 1' 'SVL 220 12' 'SWN 220 10' 'TAK 220 2' 'TAK 220 4' 'WRD 220 8' Figure 86: PV curve of selected 220 kV buses in UNI region for pre-contingency winter 18:00 scenario

1.04

1.02

0.98

0.96

Bus Voltage (pu) 0.94

0.92

0.9 790 840 890 940 990 1040 1090 1140 1190 1240 1290 Load Limit (MW)

'ASB 220 52' 'BRY 220 101' 'CUL 220 22' 'CUL 220 39' 'ISL 220 52' 'KIK 220 30' 'OPI 220 1' 'OPI 220 2' 'STK 220 8' 'TIM 220 2' 'TIM 220 5' 'WPR 220 33' 'WPR 220 37'

Figure 87: PV curve of selected 220 kV buses in USI region for pre-contingency winter 07:00 scenario

1.04

1.02

0.98

0.96

Bus Voltage (pu) 0.94

0.92

0.9 960 1010 1060 1110 1160 1210 1260 1310 1360 1410 Load Limit (MW)

'ASB 220 52' 'BRY 220 101' 'CUL 220 22' 'CUL 220 39' 'ISL 220 52' 'KIK 220 30' 'OPI 220 1' 'OPI 220 2' 'STK 220 8' 'TIM 220 2' 'TIM 220 5' 'WPR 220 33' 'WPR 220 37'

Figure 88: PV curve of selected 220 kV buses in USI region for pre-contingency winter 08:00 scenario

1.04

1.02

0.98

0.96

Bus Voltage (pu) 0.94

0.92

0.9 760 860 960 1060 1160 1260 1360 Load Limit (MW)

'ASB 220 52' 'BRY 220 101' 'CUL 220 22' 'CUL 220 39' 'ISL 220 52' 'KIK 220 30' 'OPI 220 1' 'OPI 220 2' 'STK 220 8' 'TIM 220 2' 'TIM 220 5' 'WPR 220 33' 'WPR 220 37'

Figure 89: PV curve of selected 220 kV buses in USI region for pre-contingency winter 11:00 scenario

1.04

1.02

0.98

0.96

Bus Voltage (pu) 0.94

0.92

0.9 730 830 930 1030 1130 1230 1330 1430 Load Limit (MW)

'ASB 220 52' 'BRY 220 101' 'CUL 220 22' 'CUL 220 39' 'ISL 220 52' 'KIK 220 30' 'OPI 220 1' 'OPI 220 2' 'STK 220 8' 'TIM 220 2' 'TIM 220 5' 'WPR 220 33' 'WPR 220 37'

Figure 90: PV curve of selected 220 kV buses in USI region for pre-contingency winter 12:00 scenario

1.04

1.02

0.98

0.96

Bus Voltage (pu) 0.94

0.92

0.9 720 820 920 1020 1120 1220 1320 1420 Load Limit (MW)

'ASB 220 52' 'BRY 220 101' 'CUL 220 22' 'CUL 220 39' ISL 220 'KIK 220 30' 'OPI 220 1' 'OPI 220 2' STK 220 TIM 220 'TIM 220 5' 'WPR 220 33' 'WPR 220 37'

Figure 91: PV curve of selected 220 kV buses in USI region for pre-contingency winter 13:00 scenario

1.06

1.04

1.02

0.98

0.96

0.94 Bus Voltage (pu) 0.92

0.9

0.88 720 820 920 1020 1120 1220 1320 1420 Load Limit (MW)

'ASB 220 52' 'BRY 220 101' 'CUL 220 22' 'CUL 220 39' 'ISL 220 52' 'KIK 220 30' 'OPI 220 1' 'OPI 220 2' 'STK 220 8' 'TIM 220 2' 'TIM 220 5' 'WPR 220 33' 'WPR 220 37'

Figure 92: PV curve of selected 220 kV buses in USI region for pre-contingency winter 14:00 scenario

1.04

1.03

1.02

1.01

0.99 Bus Voltage (pu) 0.98

0.97

0.96 770 870 970 1070 1170 1270 1370 Load Limit (MW)

'ASB 220 52' 'BRY 220 101' 'CUL 220 22' 'CUL 220 39' 'ISL 220 52' 'KIK 220 30' 'OPI 220 1' 'OPI 220 2' 'STK 220 8' 'TIM 220 2' 'TIM 220 5' 'WPR 220 33' 'WPR 220 37'

Figure 93: PV curve of selected 220 kV buses in USI region for pre-contingency winter 16:00 scenario

1.04

1.02

0.98

0.96

Bus Voltage (pu) 0.94

0.92

0.9 830 930 1030 1130 1230 1330 1430 Load Limit (MW)

'ASB 220 52' 'BRY 220 101' 'CUL 220 22' 'CUL 220 39' 'ISL 220 52' 'KIK 220 30' 'OPI 220 1' 'OPI 220 2' 'STK 220 8' 'TIM 220 2' 'TIM 220 5' 'WPR 220 33' 'WPR 220 37'

Figure 94: PV curve of selected 220 kV buses in USI region for pre-contingency winter 17:00 scenario

1.04

1.02

0.98

0.96

Bus Voltage (pu) 0.94

0.92

0.9 910 960 1010 1060 1110 1160 1210 1260 1310 1360 Load Limit (MW)

'ASB 220 52' 'BRY 220 101' 'CUL 220 22' 'CUL 220 39' 'ISL 220 52' 'KIK 220 30' 'OPI 220 1' 'OPI 220 2' 'STK 220 8' 'TIM 220 2' 'TIM 220 5' 'WPR 220 33' 'WPR 220 37'

Figure 95: PV curve of selected 220 kV buses in USI region for pre-contingency winter 18:00 scenario

1.06

1.04

1.02

0.98

0.96 Bus Voltage (pu) Voltage Bus 0.94

0.92

0.9 970 1070 1170 1270 1370 1470 1570 1670 1770 1870 1970 Load Limit (MW) 'ALB 220 131' 'BRB 220 21' 'DRY 220 2' 'GLN 220 15' 'HEN 220 28' 'HOB 220 210' 'HPI 220 1' 'MDN 220 21' 'OTA 220 153' 'OTA 220 56' 'PEN 220 32' 'SVL 220 1' 'SVL 220 12' 'SWN 220 10' 'TAK 220 2' 'TAK 220 4' 'WRD 220 8' Figure 96: PV curve of selected 220 kV buses in UNI region for pre-contingency summer 08:00 scenario

1.04

1.03

1.02

1.01

0.99

0.98

Bus Voltage (pu) Voltage Bus 0.97

0.96

0.95

0.94 1180 1380 1580 1780 1980 2180 2380 Load Limit (MW) 'ALB 220 131' 'BRB 220 21' 'DRY 220 2' 'GLN 220 15' 'HEN 220 28' 'HOB 220 210' 'HPI 220 1' 'MDN 220 21' 'OTA 220 153' 'OTA 220 410' 'PEN 220 32' 'SVL 220 1' 'SVL 220 12' 'SWN 220 10' 'TAK 220 2' 'TAK 220 4' 'WRD 220 8' Figure 97: PV curve of selected 220 kV buses in UNI region for pre-contingency summer 10:00 scenario

1.06

1.04

1.02

0.98 Bus Voltage (pu) Voltage Bus 0.96

0.94

0.92 1200 1400 1600 1800 2000 2200 2400 2600 Load Limit (MW) 'ALB 220 131' 'BRB 220 21' 'DRY 220 2' 'GLN 220 15' 'HEN 220 28' 'HOB 220 210' 'HPI 220 1' 'MDN 220 21' 'OTA 220 153' 'OTA 220 56' 'PEN 220 32' 'SVL 220 1' 'SVL 220 12' 'SWN 220 10' 'TAK 220 2' 'TAK 220 4' 'WRD 220 8' Figure 98: PV curve of selected 220 kV buses in UNI region for pre-contingency summer 11:00 scenario

1.04

1.03

1.02

1.01

0.99

0.98 Bus Voltage (pu) 0.97

0.96

0.95 640 740 840 940 1040 1140 1240 1340 Load Limit (MW)

'ASB 220 52' 'BRY 220 101' 'CUL 220 22' 'CUL 220 39' 'ISL 220 52' 'KIK 220 30' 'OPI 220 1' 'OPI 220 2' 'STK 220 8' 'TIM 220 2' 'TIM 220 5' 'WPR 220 33' 'WPR 220 37'

Figure 99: PV curve of selected 220 kV buses in USI region for pre-contingency summer 08:00 scenario

1.03

1.02

1.01

0.99

0.98

0.97 Bus Voltage (pu) 0.96

0.95

0.94 730 830 930 1030 1130 1230 1330 Load Limit (MW)

'ASB 220 52' 'BRY 220 101' 'CUL 220 22' 'CUL 220 39' 'ISL 220 52' 'KIK 220 30' 'OPI 220 1' 'OPI 220 2' 'STK 220 8' 'TIM 220 2' 'TIM 220 5' 'WPR 220 33' 'WPR 220 37'

Figure 100: PV curve of selected 220 kV buses in USI region for pre-contingency summer 10:00 scenario

1.03

1.02

1.01

0.99

0.98 Bus Voltage (pu) 0.97

0.96

0.95 720 820 920 1020 1120 1220 1320 1420 1520 Load Limit (MW)

'ASB 220 52' 'BRY 220 101' 'CUL 220 22' 'CUL 220 39' 'ISL 220 52' 'KIK 220 30' 'OPI 220 1' 'OPI 220 2' 'STK 220 8' 'TIM 220 2' 'TIM 220 5' 'WPR 220 33' 'WPR 220 37'

Figure 101: PV curve of selected 220 kV buses in USI region for pre-contingency summer 11:00 scenario

A4.7 QV curves of winter and summer power-flow scenarios

600

400

200

0 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1 1.1 1.2 -200

-400

-600

Reactive Power Injection (MVAr) -800

-1000 Bus Voltage (pu)

ALB 220 BRB 220 DRY 220 GLN 220 HEN 220 HOB 220 HPI 220 MDN 220 OTA 220 PAK 220 PEN 220 SVL 220 SWN 220 TAK 220 WRD 220

Figure 102: QV curves of 220 kV buses in the UNI region under pre-contingent conditions – winter 13:00 scenario

600

400

200

0 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1 1.1 1.2 -200

-400

-600

Reactive Power Injection (MVAr) -800

-1000 Bus Voltage (pu)

ALB 220 BRB 220 DRY 220 GLN 220 HEN 220 HOB 220 HPI 220 MDN 220 OTA 220 PAK 220 PEN 220 SVL 220 SWN 220 TAK 220 WRD 220

Figure 103: QV curves of 220 kV buses in the UNI region HLY-TWH 1 contingency – winter 13:00 scenario

600

400

200

0 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1 1.1 1.2 -200

-400

-600 Reactive Power Injection (MVAr) -800

-1000 Bus Voltage (pu)

BRY 220 CUL 220 ISL 220 KIK 220 STK 220 WPR 220 ASB 220 TIM 220

Figure 104: QV curves of 220 kV buses in the USI region under pre-contingent conditions – winter 13:00 scenario

600

400

200

0 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1 1.1 1.2 -200

-400

-600 Reactive Power Injection (MVAr) -800

-1000 Bus Voltage (pu)

BRY 220 CUL 220 ISL 220 KIK 220 STK 220 WPR 220 ASB 220 TIM 220

Figure 105: QV curves of 220 kV buses in the UNI region ISL-LIV contingency – winter 13:00 scenario

A5 EMERGING ENERGY PROGRAMME: PLAN AND OUTCOME STRATEGY

Emerging Energy Technologies: Programme Tranche Plan

Historic Work 2016/17 2017/18 2018/19

Wind Capacity Assessment Wind

Solar PV Variability Studies Training

Solar PV System Stability

Solar PV Solar Studies

Battery Operations Impact Assessment Review Battery Storage Trial Invex Battery Storage – Next Steps Stage 1 Consideration of Economic Options for Investment Storage Battery and Policy andStandard Review Lines Company Data Exchange , Situational Situational Intelligence Programme Situational Intelligence Situational Intelligence Stage Intelligence Situational Intelligence Future Phasing… Definition Stage 1 Invex 1 Capex Initial Work

Monitoring Progress Against Transmission Tomorrow Future States (ongoing) SO Tools Review Load Forecast Review Work Packagesto be Executed with eachEmerging Technology Real Time Operations , Process and People Ancillary Services Review Assessment of Capabilities Market System Market

A5.1 Emerging Energy Technologies – Outcome Strategy Map

GLOSSARY OF TERMS AND ACRONYMS

Term Meaning ACCE Risk classes. Also DCCE, DCECE, DCCE, DEECE, MANCE, MANECE AC Alternating current ACS Asset capability statement AUFLS Automatic Under Frequency Load Shedding – Large blocks of load which are armed with automatic under-frequency load shedding relays ready to be dropped when the frequency drops below a pre- programmed threshold Bipole An electrical power transmission line having two direct-current conductors in opposite polarity Bode Plot In electrical engineering and control theory, a Bode plot is a graph of the frequency response of a system Bus (Busbar) The common primary conductor of power from a power source to two or more separate circuits. CCGT Closed-Cycle Gas Turbine CE Contingency Event (see also ECE) Code, the Electricity Industry Participation Code Contingency The uncertainty of an event occurring, and the planning to cover for it CVP Constraint Violation Penalty Dispatch Scheduling active and reactive power generation to meet demand DC Direct current ECE Extended Contingent Event - those events for which, in the reasonable opinion of the grid operator, resources can be economically provided to maintain the security of the grid and power quality with the shedding of demand. EICP Electricity Industry Participation Code (the Code) EVs Electric Vehicles FIR Fast Instantaneous Reserve – reserve required to act in the first six seconds and then maintain its post event output for 60 seconds. (See also SIR) FK Frequency Keeping FKC Frequency Keeping Control

Term Meaning FSC Frequency Stabiliser Control Fourier transform Decomposes a function of time (a signal) into the frequencies that make it up Frequency Rate of cyclic change in current and voltage, measured in Hz Frequency excursion A variation of the power system frequency above 50.25 Hz or below 49.75 Hz GAMS General Algebraic Modelling System Generator A device that converts rotating mechanical movement into electric power. The current generated can be either alternating (AC) or direct (DC). GXP Grid Exit Point HEMS Home Energy Management System HVDC High Voltage Direct Current IL Interruptible Load Insolation The solar radiation that reaches the earth's surface. It is measured by the amount of solar energy received per square centimetre per minute Inverter An apparatus which converts direct current into alternating current IR Instantaneous Reserves Irradiance See Solar Irradiance Machines Motors and generators are collectively referred to as ‘machines’ or ‘electric machines’. Motors are machines that convert electrical energy into mechanical work in the form of a rotating shaft, while generators convert the mechanical work of a rotating shaft into electricity. MCO Maximum Continuous Output Meshblock Meshblocks are the smallest geographic unit for which Statistics New Zealand collects statistical census data. MFK Multi-Frequency Keeping MOI Market Operator Interface NFR Net Free Reserve NIWA National Institute of Water and Atmospheric Research

Term Meaning NMIR National Market for Instantaneous Reserves NRSS Non-Response Schedule Short Nyquist Theorem Also known as the sampling theorem, is a principle that engineers follow in the digitization of analog signals. OCGT Open-Cycle Gas Turbine OF Over-Frequency OFA Over-Frequency Arming - The provision of equipment that enables an automatic reduction in the level of power injection into the power system to arrest an unplanned rise in system frequency. OFAS Over-Frequency Arming System PDF Probability Density Function PI Plant Information PLSR Partially-Loaded Spinning Reserve - involves offering spare generation capacity into the reserve market while dispatching energy to supply the demand. The amount of PLSR that can be obtained from a generator depends on the speed of the governor control system setup and turbine control mechanism. Power System A network of electrical components deployed to supply, transfer, and use electric power PPOs Principle Performance Obligations pu Per-unit. Expression of system quantities as fractions of a defined base unit quantity; e.g. power, voltage, current PV Photovoltaic - generating electric power by using solar cells to convert energy from the sun into a flow of electrons by the photovoltaic effect Ramp (Ramp up) Move a generator or HVDC link to a designated load level at a specified rate. RMS Reserve Management System RMTSAT Reserve Management Transient Stability Analysis Tool RoCoF Rate of Change of Frequency RTD Real-Time Dispatch (See also Dispatch) RTP Real-Time Pricing

Term Meaning SCADA Supervisory Control and Data Acquisition - a system used for monitoring, and issuing control signals to plant in the field to effect voltage control and over frequency arming. Simulink A graphical programming environment for modeling, simulating and analyzing multidomain dynamic systems. SMP Standard Maintenance Procedures SIR Slow Instantaneous Reserve - reserve required to act in the first 60 seconds and sustain its post event output for 15 minutes. (See also FIR) Solar irradiance The power per unit area received from the Sun in the form of electromagnetic radiation SPD Scheduling, Pricing and Dispatch - used to calculate the maximum welfare to the market for every trading period. (see also vSPD) Stochastic Variable that has a random probability distribution or pattern TASC Technical Advisory Services Contract three-phase, zero impedance bus fault All three phases of a substation bus (e.g. 220 kV, 110 kV, 33 kV bus) have been unintentionally connected directly to ground (i.e. 0 kV) through a zero impedance short-circuit. Transmission system Also referred to as transmission network - an electric power transmission system that interconnects generators and loads and generally provides multiple paths among them TSAT Transient Stability Analysis Tool TWD Tail Water Depressed mode - Hydro generators can be dispatched in this mode to dispatch reactive power only with no active power output. This involves a generator operating as a motor to offer frequency reserve. In this operating mode the generator shaft spins freely, resulting in no electrical energy being generated. vSPD Vectorised Scheduling, Pricing and Dispatch (see also SPD) UF Under-Frequency UNI, USI Upper North Island and Upper South Island VSAT Voltage Security Assessment Tool

Term Meaning WVM Wavelet Variability Model

BIBLIOGRAPHY

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