New Zealand (EIPC cl 8.25A) ride-through requirements
High-voltage ride-through for New Zealand. Every breakpoint below is read from the code itself, and carries the clause it came from — so you can check it, not just cite it.
What is the high-voltage ride-through envelope for New Zealand (EIPC cl 8.25A)?
The plant must ride through for any voltage that stays on or below this envelope. The envelope holds 1.2 pu from t = 0 to 2 s; then 1.15 pu from 2 s to 6 s; then 1.1 pu from 6 s onward — the last band the envelope defines, with no stated end time.
Every breakpoint is stated in the clause cited below.
Applies to Generating stations connected to the grid, both islands
| From | To | Voltage | Between the points |
|---|---|---|---|
| 0 | 2 s | 1.2 pu | Held flat |
| 2 s | 6 s | 1.15 pu | Held flat |
| 6 s | no stated end | 1.1 pu | Held flat |
The clause this came from
Electricity Industry Participation Code 2010, Part 8, cl 8.25A(1) and (6), upper boundary of Figure 8.1 / Figure 8.2 — verified in the 1 May 2025 consolidation; clause unchanged at 1 July 2026.
Operating requirements beyond the envelopes.
The envelopes above are what New Zealand (EIPC cl 8.25A) demands during a disturbance. The rows below are the same regime’s operating and fault-response requirements — reactive capability, frequency response, continuous operating range, ramp rate and fault-current injection — each researched from the document its own row cites, separately from the plotted corpus. Every row carries its clause and a verbatim quote, so you can check it the same way.
| Requirement | What the code states | Clause |
|---|---|---|
| Reactive capability — grid-connected stations Reactive capability | Export (over-excited) a minimum net reactive power of 50% of maximum continuous MW output power, and import (under-excited) a minimum of 33% of maximum continuous MW output power, measured at the generating unit terminals, over defined grid-voltage ranges Binds each generator with a point of connection to the grid, at all times while synchronised and made available for dispatch by the system operator; measured at the generating unit terminals. Voltage-dependence: the 50% export capability must be available while the grid injection point voltage is within the tabulated range (220 kV: 198-242 kV i.e. -10%/+10%; 110 kV: 99-121 kV i.e. -10%/+10%; 66/50/33 kV: -5%/+5%; 22/11 kV: -2.5%/+2.5%); the 33% import capability table is asymmetric at the two highest voltages (220 kV: 209-242 kV i.e. -5%/+10%; 110 kV: 104.5-121 kV i.e. -5%/+10%; lower voltages as for export). No charge/discharge asymmetry is stated for storage. No North/South Island differentiation in cl 8.23. Storage applicability: binds BESS explicitly via cl 8.1B(1) — the owner or operator of an energy storage system (Part 1 cl 1.1(1): 'all equipment functioning together as a single entity that is able to take electricity from a network, store the energy in another form, and provide injection') with capacity at or above the cl 8.21(1) threshold (10 MW maximum continuous MW output power) must comply with the obligations that apply to a generator or embedded generator, regardless of whether the energy storage system is discharging or charging; cl 8.1B(2) applies the cl 8.21 thresholds as if the ESS were a generator. | Clause 8.23(a) and (b) with tables, Electricity Industry Participation Code 2010, Part 8 (1 August 2026 consolidation) + Clause 8.23(b), Electricity Industry Participation Code 2010, Part 8 (1 August 2026 consolidation) |
The clauses this row citesClause 8.23(a) and (b) with tables, Electricity Industry Participation Code 2010, Part 8 (1 August 2026 consolidation) — “ Each generator with a point of connection to the grid must at all times ensure that its assets― (a) when the voltage at its grid injection point is within the applicable range of nominal voltage, are capable of exporting (over excited) when synchronised and made available for dispatch by the system operator, a minimum net reactive power which is 50% of the maximum continuous MW output power as measured at the following generating unit terminals: ” (Electricity Industry Participation Code 2010, Part 8 Common quality (1 August 2026 consolidation), accessed 2026-08-09) Clause 8.23(b), Electricity Industry Participation Code 2010, Part 8 (1 August 2026 consolidation) — “ when the voltage at its grid injection point is within the applicable range of nominal voltage, are capable of importing (under excited) when synchronised and made available for dispatch by the system operator, a minimum net reactive power which is 33% of the maximum continuous MW output power as measured at the generating unit terminals as set out below: ” (Electricity Industry Participation Code 2010, Part 8 Common quality (1 August 2026 consolidation), accessed 2026-08-09) | ||
| Reactive capability — embedded stations Reactive capability | Export a minimum reactive power of 33% and import a minimum reactive power of 33% of the embedded generating station's maximum continuous MW output power, measured at the point of connection to the local network, over defined voltage ranges Binds each embedded generator, for each embedded generating station to which Technical Code A clause 5(2A) applies — i.e. stations with maximum continuous MW output power of 10 MW or more that connect to the local network at the nominal voltage of the grid-exit-point busbar (TC A cl 5(2B)) — when synchronised with the local network, unless agreed otherwise with the distributor; it does not apply where the distributor has directed an alternative voltage control mode (TC A cl 5(2C)(a)), and stations first connected before 1 Jul 2027 that cannot comply without modification are grandfathered (TC A cl 5(2C)(b)). Voltage-dependence: export capability over 110 kV: 99-121 kV (-10%/+10%), 66/50/33 kV: -5%/+5%, 22/11 kV: -2.5%/+2.5%; import table asymmetric at 110 kV: 104.5-121 kV (-5%/+10%). Symmetric 33%/33% export/import — unlike the 50%/33% grid-connected requirement of cl 8.23. No North/South Island differentiation. Clause inserted 1 Jul 2026 by the Frequency and Voltage Related Amendments Amendment 2026. Storage applicability: binds BESS explicitly via cl 8.1B(1) — an energy storage system (Part 1 cl 1.1(1) definition) at or above the cl 8.21(1) 10 MW threshold must comply with the obligations that apply to a generator or embedded generator, whether discharging or charging; cl 8.1B(2) applies the thresholds as if the ESS were a generator. | Clause 8.23A(1)(a) and (b) with tables, Electricity Industry Participation Code 2010, Part 8 (1 August 2026 consolidation) + Clause 8.23A(1)(b), Electricity Industry Participation Code 2010, Part 8 (1 August 2026 consolidation) |
The clauses this row citesClause 8.23A(1)(a) and (b) with tables, Electricity Industry Participation Code 2010, Part 8 (1 August 2026 consolidation) — “ Unless agreed otherwise with the distributor who operates the local network, each embedded generator must ensure that each embedded generating station it owns or operates to which clause 5(2A) of Technical Code A applies is, when synchronised with the local network, at all times capable of― (a) when the voltage at the embedded generating station’s point of connection to the local network is within the applicable range of nominal voltage in the table below, exporting a minimum reactive power of 33% of the maximum continuous MW output power of the embedded generating station, as measured at the embedded generating station’s point of connection to the local network: ” (Electricity Industry Participation Code 2010, Part 8 Common quality (1 August 2026 consolidation), accessed 2026-08-09) Clause 8.23A(1)(b), Electricity Industry Participation Code 2010, Part 8 (1 August 2026 consolidation) — “ when the voltage at the embedded generating station’s point of connection to the local network is within the applicable range of nominal voltage in the table below, importing a minimum reactive power of 33% of the maximum continuous MW output power of the embedded generating station, as measured at the embedded generating station’s point of connection to the local network: ” (Electricity Industry Participation Code 2010, Part 8 Common quality (1 August 2026 consolidation), accessed 2026-08-09) | ||
| Governor droop and frequency contribution Frequency response | Speed governor and/or frequency control system with droop adjustable over the range of 1% to 7%; plus an at-all-times duty to make the maximum possible injection contribution to maintain frequency within the normal band (49.8-50.2 Hz, Part 1 definition) Technical Code A cl 5(1)(c)(ii) binds each generator for each generating unit: the governor/frequency control system must be stable with adequate damping and have droop adjustable over 1%-7%; final settings are agreed with the system operator and must not be changed without system operator approval (TC A cl 5(1)(d)). Clause 8.17 imposes the operational duty on each generator while synchronised (excluding excluded generating stations, i.e. stations below 10 MW maximum continuous MW output power per cl 8.21(1)) to make the maximum possible injection contribution to maintain and restore frequency to the normal band, assessed against the technical codes. No numeric activation time, full-response time or sustain duration is stated; frequency keeping beyond this is a dispatched ancillary service under Part 8 Subpart 3. No North/South Island differentiation in these clauses. Storage applicability: binds BESS explicitly via cl 8.1B(1) — an energy storage system (Part 1 cl 1.1(1) definition) at or above the cl 8.21(1) 10 MW threshold must comply with the obligations applying to a generator or embedded generator, whether discharging or charging; below 10 MW a station is an excluded generating station for cl 8.17 and the frequency-related Technical Code A provisions (cl 8.21(1)). | Technical Code A clause 5(1)(c)(i)-(ii), Schedule 8.3, Electricity Industry Participation Code 2010, Part 8 (1 August 2026 consolidation) + Clause 8.17, Electricity Industry Participation Code 2010, Part 8 (1 August 2026 consolidation) |
The clauses this row citesTechnical Code A clause 5(1)(c)(i)-(ii), Schedule 8.3, Electricity Industry Participation Code 2010, Part 8 (1 August 2026 consolidation) — “ each of its generating units has a speed governor and/or frequency control system that― (i) provides stable performance with adequate damping; and (ii) has an adjustable droop over the range of 1% to 7%; and ” (Electricity Industry Participation Code 2010, Part 8 Common quality (1 August 2026 consolidation), accessed 2026-08-09) Clause 8.17, Electricity Industry Participation Code 2010, Part 8 (1 August 2026 consolidation) — “ Each generator (while synchronised) and the HVDC owner must at all times ensure that its assets, other than any generating units within an excluded generating station, make the maximum possible injection contribution to maintain frequency within the normal band (and to restore frequency to the normal band). Any such contribution must be assessed against the technical codes. ” (Electricity Industry Participation Code 2010, Part 8 Common quality (1 August 2026 consolidation), accessed 2026-08-09) | ||
| Frequency control dead band Frequency response | Dead band not exceeding the greater of ±0.1 Hz or the generating unit's inherent dead band (as agreed with the system operator acting reasonably) Technical Code A cl 5(1)(c)(iv), inserted 1 Jul 2026 by the Frequency and Voltage Related Amendments Amendment 2026; binds each generator for each generating unit's speed governor and/or frequency control system. Transition: for units electrically connected before 1 Jul 2026 the requirement applies only from the unit's next periodic test under Appendix B of Technical Code A (TC A cl 5(1A)); geothermal-primary units are exempt (TC A cl 5(1AB)). No North/South Island differentiation. Storage applicability: binds BESS explicitly via cl 8.1B(1) — an energy storage system (Part 1 cl 1.1(1) definition) at or above the cl 8.21(1) 10 MW threshold must comply with obligations applying to a generator or embedded generator, whether discharging or charging; stations below 10 MW are excluded generating stations for the frequency-related Technical Code A provisions (cl 8.21(1)), and stations that would newly lose excluded status because of the 2026 amendments can retain it under the cl 8.21(3)-(4) grandfathering conditions. | Technical Code A clause 5(1)(c)(iv), Schedule 8.3, Electricity Industry Participation Code 2010, Part 8 (1 August 2026 consolidation) + Technical Code A clause 5(1A), Schedule 8.3, Electricity Industry Participation Code 2010, Part 8 (1 August 2026 consolidation) |
The clauses this row citesTechnical Code A clause 5(1)(c)(iv), Schedule 8.3, Electricity Industry Participation Code 2010, Part 8 (1 August 2026 consolidation) — “ operates with a dead band not exceeding the greater of; (A) ±0.1 Hertz; or (B) the inherent dead band of the generating unit, as agreed with the system operator acting reasonably; and ” (Electricity Industry Participation Code 2010, Part 8 Common quality (1 August 2026 consolidation), accessed 2026-08-09) Technical Code A clause 5(1A), Schedule 8.3, Electricity Industry Participation Code 2010, Part 8 (1 August 2026 consolidation) — “ For a generator with a generating unit that has electrically connected to a network prior to the commencement of the Electricity Industry Participation Code (Frequency and voltage related amendments) Amendment 2026, the requirement in subclause (1)(c)(iv) only applies from the time of the next periodic test of the generating unit carried out in accordance with Appendix B of Technical Code A following the commencement of the Electricity Industry Participation Code (Frequency and voltage related amendments) Amendment 2026. ” (Electricity Industry Participation Code 2010, Part 8 Common quality (1 August 2026 consolidation), accessed 2026-08-09) | ||
| Continuous voltage operating range Continuous operating range | Generator assets must be capable of operating with the grid voltage anywhere within: 220 kV nominal: 198-242 kV (-10.0%/+10.0%); 110 kV: 99-121 kV (-10.0%/+10.0%); 66 kV: 62.7-69.3 kV (-5.0%/+5.0%); 50 kV: 47.5-52.5 kV (-5.0%/+5.0%) Cl 8.22(1) sets the voltage ranges grid owners must maintain capability for, measured at the high-voltage terminals of the grid owner's transformers at each grid injection point and grid exit point (or at the point itself if no transformer); cl 8.22(2) then binds each generator with a point of connection to the grid to ensure its assets are capable of being operated, and do operate, whenever the grid is operated within those ranges. This is the steady-state operating band, distinct from the cl 8.25A fault ride-through no-trip zones (which are on this site's island-variant curve pages). No time-limited voltage steps are stated in cl 8.22. No North/South Island differentiation. Continuous frequency band: the Code states no separate continuous frequency operating band for generators; the frequency envelope is the cl 8.19 under-frequency sustain-output requirement (North Island cl 8.19(1): envelope down to 47.0 Hz; South Island cl 8.19(3): above 47 Hz at all times and 30 s between 45-47 Hz), covered by the ride-through curves published for this code and not repeated here. Storage applicability: binds BESS explicitly via cl 8.1B(1) — an energy storage system (Part 1 cl 1.1(1) definition) at or above the cl 8.21(1) 10 MW threshold complies with generator obligations whether discharging or charging; cl 8.22 is not among the clauses subject to the excluded-generating-station carve-out in cl 8.21(1). | Clause 8.22(1) with table, Electricity Industry Participation Code 2010, Part 8 (1 August 2026 consolidation) + Clause 8.22(2), Electricity Industry Participation Code 2010, Part 8 (1 August 2026 consolidation) |
The clauses this row citesClause 8.22(1) with table, Electricity Industry Participation Code 2010, Part 8 (1 August 2026 consolidation) — “ Each grid owner must ensure that its assets at and in between― (a) the high voltage terminals of the grid owner's transformers at each grid injection point and grid exit point; or (b) if no transformer exists, the relevant grid injection point or grid exit point― are capable of being operated within the following range of voltages: 220 | 198 | -10.0% | 242 | 10.0% — 110 | 99 | -10.0% | 121 | 10.0% — 66 | 62.7 | -5.0% | 69.3 | 5.0% — 50 | 47.5 | -5.0% | 52.5 | 5.0% ” (Electricity Industry Participation Code 2010, Part 8 Common quality (1 August 2026 consolidation), accessed 2026-08-09) Clause 8.22(2), Electricity Industry Participation Code 2010, Part 8 (1 August 2026 consolidation) — “ Each generator with a point of connection to the grid must at all times ensure that its assets are capable of being operated, and do operate, when the grid is operated within the range of voltages set out in subclause (1). ” (Electricity Industry Participation Code 2010, Part 8 Common quality (1 August 2026 consolidation), accessed 2026-08-09) | ||
| Ramp-rate treatment Ramp rate | No numeric MW/min ramp limit: the rate of change of each generating unit's output must not adversely affect the system operator's ability to comply with the principal performance obligations, and must be adjustable to allow for changes in grid conditions Technical Code A cl 5(1)(b) binds each generator for each generating unit; the constraint is qualitative (no Code-stated MW/min or %/min figure) plus a mandatory adjustability capability. Actual limits end up in the asset capability statement, within whose limits assets must be designed and operated (TC A cl 2(1)(b)). For load, cl 8.18 separately requires each purchaser to limit instantaneous changes and the net rate of change in offtake to levels the system operator reasonably requires — relevant to a BESS's charging side only to the extent obligations applying to purchasers would attach, which cl 8.1B(1) disapplies for qualifying storage (a qualifying ESS complies only with generator/embedded-generator obligations even when charging). No separate charge/discharge ramp values are stated. No North/South Island differentiation. Storage applicability: binds BESS explicitly via cl 8.1B(1) — an energy storage system (Part 1 cl 1.1(1) definition) at or above the cl 8.21(1) 10 MW threshold complies with generator obligations whether discharging or charging. | Technical Code A clause 5(1)(b), Schedule 8.3, Electricity Industry Participation Code 2010, Part 8 (1 August 2026 consolidation) |
The clause this row citesTechnical Code A clause 5(1)(b), Schedule 8.3, Electricity Industry Participation Code 2010, Part 8 (1 August 2026 consolidation) — “ the rate of change in the output of any of its generating units does not adversely affect the system operator's ability to plan to comply, and to comply, with the principal performance obligations. The rate of change must be adjustable to allow for changes in grid conditions; and ” (Electricity Industry Participation Code 2010, Part 8 Common quality (1 August 2026 consolidation), accessed 2026-08-09) | ||
| Reactive current and active power during/after faults Fault-current injection | Reactive current opposing the terminal-voltage change for the 6 seconds following fault commencement, capped at the maximum transient reactive current in the asset capability statement (no numeric gain k stated); after clearance, active power at least in proportion to grid voltage relative to pre-fault output for 6 seconds Cl 8.25B(1)-(2) binds each generator for each generating unit; reactive-current direction is specified (oppose the change in terminal voltage) but the magnitude/gain is set by the unit's own asset capability statement, not by a Code-wide k-factor; no negative-sequence current requirement and no explicit reactive-vs-active priority rule are stated. The fault types triggering the obligation are those of cl 8.25A(1) — a zero impedance three-phase or unbalanced short circuit on any part of the grid at 110 kV or 220 kV in the island in which the asset is connected — and the associated no-trip zones are island-specific (Figure 8.1 North Island, Figure 8.2 South Island; on this site's curve pages), while the cl 8.25B injection obligation itself is worded identically for both islands. Exemptions: does not apply to any asset at an excluded generating station (cl 8.25D(b), i.e. below 10 MW maximum continuous MW output power per cl 8.21(1)) or to a wind station operating below 5% of rated MW (cl 8.25D(a)); the active-power recovery duty does not apply to a wind station whose wind resource dropped during the 6 s after fault commencement (cl 8.25B(3)). Storage applicability: binds BESS explicitly via cl 8.1B(1) — an energy storage system (Part 1 cl 1.1(1) definition) at or above the cl 8.21(1) 10 MW threshold complies with generator obligations whether discharging or charging. | Clause 8.25B(1), Electricity Industry Participation Code 2010, Part 8 (1 August 2026 consolidation) + Clause 8.25B(2), Electricity Industry Participation Code 2010, Part 8 (1 August 2026 consolidation) |
The clauses this row citesClause 8.25B(1), Electricity Industry Participation Code 2010, Part 8 (1 August 2026 consolidation) — “ Each generator must ensure that each of its generating units generates reactive current to oppose the change in its terminal voltage without exceeding the maximum transient reactive current specified in the generator's asset capability statement for the period of 6 seconds immediately following the commencement of a fault on the grid of a type described in clause 8.25A(1). ” (Electricity Industry Participation Code 2010, Part 8 Common quality (1 August 2026 consolidation), accessed 2026-08-09) Clause 8.25B(2), Electricity Industry Participation Code 2010, Part 8 (1 August 2026 consolidation) — “ Each generator must ensure that each of its generating units provides active power output relative to pre-fault active power output at least in proportion to the grid voltage at the grid injection point for the period of 6 seconds immediately following the clearance of a fault on the grid of a type described in clause 8.25A(1). ” (Electricity Industry Participation Code 2010, Part 8 Common quality (1 August 2026 consolidation), accessed 2026-08-09) | ||
Who does New Zealand (EIPC cl 8.25A) bind, and since when?
Generating stations connected to the grid, both islands. No date of effect is published here — grid codes are reissued, so check the current issue before relying on it.
These figures are a reading aid, not legal advice. Grid codes are reissued: verify against the current edition before you design to them.
Curve data last checked against the code on — 66 standards, 130 envelopes, published by bess.engineer under CC BY 4.0.
Questions this page answers about New Zealand (EIPC cl 8.25A)
- Does New Zealand (EIPC cl 8.25A) require ride-through, or only that the plant does not trip?
- Ride-through. Every envelope on this page is a performance duty the plant must meet, not a protection-setting no-trip boundary — they are different obligations. That is what these curves are; they are not everything New Zealand (EIPC cl 8.25A) contains. The requirement sentence under each chart says which side of the curve is the compliant one.
- Are the numbers on this page taken from New Zealand (EIPC cl 8.25A) itself?
- Yes. Every breakpoint is read from the code, and each envelope carries the clause it came from, quoted in full under its chart — so you can check the figure against the standard rather than cite it from this page.
- Which events are charted for New Zealand (EIPC cl 8.25A)?
- New Zealand (EIPC cl 8.25A) is charted here with 1 envelope — high-voltage ride-through (HVRT). No low-voltage or frequency envelope is charted here — check New Zealand (EIPC cl 8.25A) itself before concluding it sets none.
Ride-through, in context.
An envelope is a compliance boundary; understanding why it exists is a different question. The ride-through and grid-forming entries cover the engineering, and the Engineering Foundations course builds it from the physics up.
Also for New Zealand: New Zealand North Island (EIPC cl 8.19(1)), New Zealand North Island (EIPC cl 8.25A), New Zealand South Island (EIPC cl 8.25A)
Elsewhere in Asia-Pacific: Singapore (EMA Transmission Code App. F6), South Korea (KEPCO), Sri Lanka (CEB), and 9 more