Beyond the 10 kW Export Limit

The Electricity Authority has called for submissions on allowing households to export up to 10 kW from their rooftop solar systems — an important step toward unlocking more distributed generation across New Zealand.

But this consultation also acknowledges what many consumers have known for years: the long-standing 5 kW limit was never technically necessary. With today’s smart inverters, advanced metering, and growing electrification of homes and transport, the 5 kW cap has become a barrier to progress.

This Q&A submission argues the Authority should go further — enabling future-ready homes and communities to install three-phase, 15 kW systems (or more) with intelligent export management, dynamic operating envelopes, and incentives that reward participation in a smarter, more flexible grid.

Q1. What are your views on the proposal to set a default 10kW export limit for Part 1A applications?

A 10 kW single-phase limit is sufficient to meet most households’ winter needs, particularly as heating, hot water, and EV charging increase.
However, in summer this capacity will often produce significant surplus generation, which if unmanaged could create local voltage issues.
Rather than curtail this clean energy, EDBs and DSOs should plan now to harness it — through dynamic operating envelopes (DOEs), local energy trading, community storage, and vehicle-to-grid (V2G) participation.
With real-time visibility and responsive HEMs, this surplus can strengthen the grid and lower costs instead of being wasted.

Q2. What are your views on the Code clarifying that a distributor cannot limit the nameplate capacity of a Part 1A application, unless the capacity exceeds 10kW?

The 5 kW limit was always understood by EDBs to be technically conservative and unlikely to cause network issues, yet it was enforced as a blanket rule.
While this was permissible under existing standards, it represented risk aversion rather than leadership in preparing for the energy transition.
Going forward, we need EDBs to proactively enable distributed energy rather than constrain it — using smart-meter data, real-time visibility, and dynamic operating envelopes to manage local voltage rather than rely on static export limits.

Q3. There are requirements for distributors in Proposal A1. Which of these do you support, or not support, and why?

Current inverter settings are often locked by administrators, preventing customers from using the full functionality of their devices. This can conflict with more effective, customer-led ways of managing grid stability such as smart HEMS or aggregated flexibility controls. EDBs require clear guidance and visibility rather than restrictive control. Without access to real-time LV data, they are effectively operating blind on “our” shared grid — the same network consumers invest in through their DER assets. The Electricity Authority should require EDBs to use existing AMI data (via the Consumer Data Right) to gain visibility, rather than rely on restrictive administrative settings. The goal should be coordination, not control — enabling DSOs and consumers to collaborate using data and price signals, rather than locking down flexibility through centralised limits.

Q4. What are your views on the proposal for industry to develop an export limits assessment methodology?

Take learnings from Australia and act now

  1. Use AMI via CDR now: Mandate ICP-level voltage/PQ access so DSOs can run LV visibility without new hardware; publish feeder/phase dashboards.
  2. DOEs as signals (not hard commands): Publish per-phase headroom + locational prices; define control hierarchy (inverter = safety, HEMS = optimisation, DSO = signals).
  3. Three-phase pathway for >10 kW: Make residential three-phase price-neutral; set a simple national imbalance limit; fast-track upgrades where it avoids reinforcement.
  4. Shared-savings, not subsidies: Offer small credits/export uplifts tied to avoided capex and proven stability (phase balance, voltage hygiene).
  5. V2G readiness: Prefer three-phase bidirectional chargers; allow P2P participation; enrol EVs in DOEs for evening peaks.
  6. Interoperability + standards: Require open APIs (IEEE 2030.5/CSIP-Aus, OCPP) and data portability; avoid vendor lock-in.
  7. Equity and rentals: Support participation for renters/social housing (portable EV/V2G, controlled loads) so benefits aren’t limited to owners.
  8. Installer guidance + accreditation: One-page national guide (when to specify three-phase & V2G-ready); recognise HEMS competence in approvals.
  9. Regulatory sandbox + KPIs: 12-month feeders pilot; targets: over-voltage minutes ↓ ≥50%, phase-spread events ↓ ≥50%, curtailment ↓ ≥30–50%, documented capex deferral.
  10. Fallback & consumer protections: If data/control fails, revert to conservative static export + grid-support modes; clear dispute/escalation path.

Bottom line: Act early with transparency, open standards, and shared-savings. Let consumers and DSOs collaborate via price/visibility signals so we avoid Australia’s “cap first, fix later” trap.

Q5. What would you do differently in Proposal A1, if anything?

An online registration form, linked through the Consumer Data Right (CDR) “Open Electricity” framework, should allow consumers or their installers to directly update EDB databases with details of installed or planned flexible devices — such as PV, batteries, EV chargers, and controlled loads.
This visibility is essential for DSOs to identify where flexibility exists and to plan local balancing or congestion relief efficiently. Participation should be treated as a normal user responsibility, not voluntary — similar to how meter data is shared today.
It ensures that grid operators have accurate information while avoiding unnecessary administration costs currently charged by EDBs for manual connection assessments.
This streamlined, CDR-enabled process would lower costs, improve transparency, and let DSOs coordinate flexibility safely and fairly without needing expensive new monitoring systems.

Q6. What concerns, if any, do you have about requiring the 2024, rather than 2016, version of the inverter installation standard for Part 1A applications?

We support the 2024 direction (10 kW single-phase, modern inverter settings) as a pragmatic step—provided it’s paired with consumer-centric measures.

Expectations for the next iteration (commit in principle now, deliver over 12–18 months):

  1. Unlock AMI data via CDR: ICP-level voltage/PQ access for designers and HEMs; no new EDB hardware.
  2. DOEs as signals, not hard commands: Publish per-phase headroom + locational prices; define control hierarchy (inverter = safety, HEMS = optimisation, DSO = signals).
  3. Phase balance rule + three-phase pathway: A simple national imbalance limit and a clear path for >10 kW homes to move to three-phase (price-neutral at residential kVA).
  4. Shared-savings incentives: Small annual credits/export uplifts where customer upgrades avoid reinforcement (no subsidies; share avoided cost).
  5. V2G readiness: Prefer three-phase bidirectional chargers for high-power export; enrol in DOEs and allow P2P participation.
  6. Real-time visibility: DSO dashboards/API showing feeder/phase voltage and congestion so flexible HEMs can respond.
  7. DLMP pilots: Tie a small slice of EDB revenue to local performance (voltage spread, congestion, losses) to reward efficient operation.
  8. Installer guidance: Publish a one-page national guide: “When to specify three-phase & V2G-ready” (≥8–10 kW PV, two EVs, all-electric).
  9. KPIs & timeline: Over-voltage minutes ↓ ≥50%, phase-spread events ↓ ≥50%, curtailment ↓ ≥30–50%; pilot report-back in 12 months.

Bottom line: 2024 settings are fit for purpose; the next iteration should lock in data access, price signals, and shared-savings so consumers, HEMs, and DSOs collaborate—and upgrades are the last resort, not the default.

Q7. Do you support amending the New Zealand volt-watt and volt-var settings to match the Australian values for Part 1A applications – why or why not – what do you think are the implications?

These should be last-resort tools to safeguard the shared grid, activating only when genuine stress is occurring.
Under normal operation, Dynamic Operating Envelopes (DOEs) should adjust exports proactively and gradually — long before conditions become critical — so that network stability is maintained without disrupting consumer generation or autonomy.
This ensures grid safety while preserving public trust and confidence in the fairness of distributed generation controls.

Q8. What would you do differently in Proposal A2, if anything?   

Support the flexibility it offers but require that any EDB-set export limits are evidence-based, transparent, and consistent.
Specifically, limits should be justified using smart-meter (AMI) voltage data made accessible through the Consumer Data Right (CDR) so DSOs can demonstrate real network constraints without extra monitoring costs.
The EA should also provide national guidance on control hierarchy to prevent conflicts between inverter software, distributor controls, and consumer HEMs.
This ensures fairness, consumer trust, and efficient use of existing infrastructure.

Q9.  Do you have any concerns about the Authority citing the Australian disconnection settings for inverters when high voltage is sustained?

If the system can operate safely, there is no reason to restrict generation. Control measures should be last-resort tools, activated only when the network is under genuine stress.
With smart-meter visibility and Dynamic Operating Envelopes (DOEs) in place, DSOs can anticipate issues and adjust exports smoothly, long before critical limits are reached.
Under Dynamic Locational Marginal Pricing (DLMP), this operational flexibility actually becomes an opportunity — EDBs can earn more revenue by efficiently delivering local energy over their existing assets, effectively “sweating the network” instead of building new capacity.
This rewards proactive, data-driven management and aligns EDB incentives with consumer participation and overall system efficiency.

Q10. Do you have any concerns about the Authority requiring the latest version of the inverter performance standard for Part 1A applications?

The proposal should proceed provided it meets the aims outlined above — enabling visibility, consumer participation, and proactive management through DOEs, HEMs, and CDR data access.
If these supporting measures are not yet in place, then the regulatory framework will need an urgent upgrade to ensure safety, transparency, and fairness under higher export limits.
This is an opportunity for New Zealand to learn from Australia’s experience and lead, showing how proactive visibility, open data, and collaboration can unlock growth in distributed generation without costly grid upgrades.

Q11. What are your views on the proposal that where distributors set bespoke export limits for Part 2 applications, they must do so using the industry developed assessment methodology?

A bespoke approach may be justified where existing grid assets are sub-standard or nearing capacity, but any deviation should remain consistent with national standards.
Upgrades should proceed only where they clearly enhance the network’s ability to host future distributed generation and manage flexibility, not simply to maintain outdated configurations.
Any bespoke work should also feed learnings back into national design standards, so each upgrade helps lift overall system performance and resilience.

Q12. What are your views on the several requirements that must be adhered to regarding the distributors’ documentation (see paragraph 5.96) relating to setting export limits under Part 2?

Paragraph 5.96 appropriately recognises the need for EDB discretion, but it must be exercised to lift standards, not lower them.
We support discretion only where it demonstrably improves network capability—for example, by trialling smarter technologies, data sharing, or flexibility tools that enhance the grid’s future performance.
Any such variations should use smart-meter evidence, be fully transparent, and feed learnings back into national standards so innovation raises the baseline for all.
This ensures discretion becomes a pathway for improvement, acknowledging the smart ideas and technologies that will inevitably emerge.

Q13. Do you agree it is fair and appropriate that where distributors set export limits for Part 2 applications, applicants can dispute the limit? If so, what sort of process should that entail?

The EA appears too focused on allowing EDBs to lower technical or connection standards, rather than expecting them to continuously improve.
Discretion should not become a back door for restriction; it should be a mechanism for innovation and uplift — supporting pilots, smarter tools, and modernised practices that raise overall capability.
Consumers have already invested in intelligent devices; regulation should ensure those capabilities are enabled, not disabled. New Zealand’s credibility as a flexible-grid leader depends on raising—not relaxing—standards.
By setting clear expectations that discretion must deliver measurable improvement, the EA can encourage EDBs to demonstrate leadership, share learnings, and build public trust in the transition to a smarter, more efficient grid.

Q14. What would you do differently in Proposal B, if anything?   

Proposal B would re-centralise control with EDBs and risk recreating the very fragmentation and inconsistency that this review aims to fix.
While flexibility is important, removing the national default would undermine consumer confidence and create barriers for installers and aggregators. Instead, the EA should retain a national 10 kW baseline (Proposal A1) and build on it with the supporting measures already outlined — open data via CDR, DOEs as visibility signals, three-phase evolution, and shared-savings incentives.
If Proposal B proceeds at all, it should only be as a limited sandbox mechanism for EDBs that commit to transparency, public reporting, and data sharing. Bottom line: keep a clear national standard that protects consumers, but allow innovation under open, evidence-based conditions — not through deregulation.  

Q15. What are your thoughts on requiring the inverter performance standard (AS/NZS 4777.2:2020 incorporating Amendments 1 and 2) for low voltage DG applications in New Zealand? 

We support full alignment with AS/NZS 4777.2:2020 (Amd 1 & 2) for inverter safety and grid-support functions (Volt-Var, Volt-Watt, frequency-watt). To coordinate flexibility at scale, the Authority should lead with OpenADR (2.0) as the primary signal layer for events/prices/needs to HEMs and aggregators, and use IEEE 2030.5/CSIP-Aus only where device-level telemetry or safety functions are required.

Control hierarchy to avoid conflicts:

This approach preserves a single trans-Tasman equipment market (4777.2 + 2030.5/CSIP-Aus), prevents controller conflicts, and accelerates consumer-centric flexibility by using OpenADR for market signals while retaining 4777.2 compliance for device behaviour.  

Q16. Do you consider the transitional arrangements workable regarding requirements and timeframes? If not, what arrangements would you prefer?

Delays and piecemeal rules force consumers to “do it twice” — they can’t fully utilise their roof the first time, then must revisit later at high labour cost. To avoid costly rework, the EA should enable a single-visit pathway now:

This approach prevents stranded labour, supports electrification (EVs, winter coverage), and delivers a fair, future-ready outcome without waiting for another regulatory cycle.

Q17. What are your views on the objective of the proposed amendments?

EDBs should publish feeder plans showing how much three-phase uptake is needed to keep LV stability manageable without major upgrades as EVs and PV scale.
For example: “On Feeder X, modelling indicates ~30% of ICPs with three-phase inverters (or equivalent phase-balancing via HEMS/V2G) maintains voltage and phase symmetry within targets at high PV/EV penetration.”

What the plan should include:

This makes expectations clear for consumers/installers, enables single-visit designs (go three-phase now), and lets DSOs sweat existing assets instead of defaulting to capex.

Q18. Do you agree the benefits of the proposed amendments outweigh their costs? If not, why not?

If EDBs focus on proactive planning and data transparency, the need for physical upgrades will be minimal.
What’s required is genuine collaboration between EDBs, installers, designers, and customers to find the least-cost, highest-benefit solutions — such as targeted three-phase upgrades, phase balancing, or flexible demand participation.
By sharing feeder data and forward plans early, EDBs can enable consumers to design once, invest confidently, and avoid costly rework.
The Electricity Authority should incentivise collaboration outcomes — for example, through shared-savings or avoided-capex credits where joint planning defers infrastructure upgrades.
No plan is a plan to fail: without open collaboration and clear feeder-level roadmaps, costs rise for everyone and the transition slows unnecessarily. Under a Dynamic Locational Marginal Pricing (DLMP) model, this shift also flips EDB revenue from capex expansion to operational efficiency — rewarding networks for sweating existing assets and maintaining stability with smart tools rather than new hardware.

This approach aligns technical efficiency with fairness: everyone benefits when visibility replaces guesswork and coordination replaces control.

Q19. What are your views on the Authority’s estimate of costs of lost benefits from a 5kW export limit?

Lost benefits and social licence:
The historic 5 kW cap constrained exports even where feeders had headroom (built for peaks), creating avoidable lost benefits and eroding consumer trust. Early adopters must now revisit systems and pay extra to realise the EA’s stated goal of maximising production and benefits. While Aurora, Powerco and Northpower have corrected course at 10 kW, confidence will only be rebuilt if we pair higher limits with transparency (CDR/AMI data), DOEs-as-signals, and a price-neutral pathway to three-phase for larger, electrified homes.

Move beyond 10 kW by establishing a three-phase pathway to 15–20 kW total for electrified homes (2 EVs, all-electric) with DOEs as signals, per-phase limits, and price-neutral three-phase at residential capacity. Avoid 15 kW on single-phase (exceeds practical 63 AMP margin); instead, publish feeder-level headroom and phase-balance targets, unlock CDR/AMI voltage data, and adopt shared-savings so EDBs “sweat assets” and consumers design once. This repairs trust and aligns incentives without defaulting to blunt curtailment.

Q20. Are there costs or benefits to any parties (eg, distributors, DG owners, consumers, other industry stakeholders) not identified that need to be considered?

Left to legacy settings, the transition risks looking unfair: EDBs spend little beyond planning, while installers visit twice, DG owners pay twice, and consumers keep paying high prices until competition from cheap sunshine finally forces fossil out. Trust erodes.

Do it right with a managed glide-path:

Bottom line: Cheap sunshine will win. The EA’s job is to make the landing fair—shift EDB incentives to operation (DLMP), unlock data (CDR), enable single-visit designs and P2P/V2G—so consumers, installers, and DSOs all benefit on the way to fossil-free. “No plan is a plan to fail.”

Q21. Do you agree the proposed Code amendments are preferable to the other options? If you disagree, please explain your preferred option in terms consistent with the Authority’s main statutory objective in section 15 of the Electricity Industry Act 2010

Yes — section 15 is the legal foundation required to enable the consumer-centric, data-driven, and distributed model described above.
The Electricity Authority and MBIE must jointly establish a statutory framework that:

  1. Defines the Distribution System Operator (DSO) role — making visibility, open data, and collaboration core legal duties of EDBs, not discretionary activities.
  2. Mandates the release of ICP-level AMI data under the Consumer Data Right (Open Electricity) so that planners, designers, aggregators, and households can participate transparently.
  3. Recognises Dynamic Operating Envelopes (DOEs) and Dynamic Locational Marginal Pricing (DLMP) as standard market instruments — giving them explicit standing under the Code and enabling EDB revenue to shift from capex returns to performance-based income.
  4. Protects consumer agency — establishing that control signals (OpenADR, DOEs) are visibility and price mechanisms, not remote commands, ensuring optimisation remains with the consumer’s HEMS or aggregator.
  5. Aligns all existing Acts and Codes (Electricity Industry Act, Part 6 of the Code, the Consumer Data Right regulations, and the Distribution Pricing Principles) to remove conflicts that currently slow distributed-energy participation.
  6. Requires transparency and accountability — public reporting of LV voltage metrics, phase balance, curtailment minutes, and shared-savings outcomes.

This reform is indeed ambitious, but it’s the necessary legal scaffolding for a modern, flexible, low-carbon grid. Without it, the transition will remain patchy, slow, and inequitable.
With it, New Zealand can lead globally — proving that open data, smart pricing, and collaborative regulation can replace the old capex-driven model while lowering costs for everyone.

Q22. Do you agree the Authority’s proposed amendments comply with section 32(1) of the Act?

Section 32(1) of the Electricity Industry Act 2010 gives the Electricity Authority both the power and the duty to make and amend the Code for the long-term benefit of consumers by promoting competition, reliability, and efficiency. That mandate is already sufficient to act; it does not require new legislation or prolonged consultation cycles.

The Authority is therefore obliged to move decisively—to convert consultation findings into rules that enable open data, dynamic operating envelopes, and performance-based pricing (DLMP). Continued delay or incrementalism now causes tangible consumer harm: stranded solar investment, repeated site-work costs, avoidable curtailment, and erosion of trust in both EDBs and the regulatory process.

Acting under section 32(1) means exercising leadership, not caution. The Authority has the statutory backing to:

In short: the EA already holds the keys. Each year of delay deepens inequity and foregoes proven consumer savings. The long-term benefit of consumers now depends on timely rule-making, not further consultation.

Q23. Do you have any comments on the drafting of the proposed amendment?

No further technical comments.
We simply urge the Authority to act with the urgency that Section 32(1) already empowers — translating years of consultation into practical, enforceable rules that enable participation, restore trust, and lower costs for consumers.
New Zealand has the tools, data, and technology today; what’s missing is timely regulatory courage.

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