OT_163: Aurora Energy (2024) — Pricing Methodology (1 April 2024; RY25 delivery prices; Control Period Demand…

OT_163: Aurora Energy (2024) — Pricing Methodology (1 April 2024; RY25 delivery prices; Control Period Demand…

Source

https://www.auroraenergy.co.nz/ — original source (opens in a new tab; the file is not redistributed)

Aurora Energy (2024) — Pricing Methodology (1 April 2024) (OT_163)

The primary behind Aurora's CPD tariff — and it REFUTES the "$1.50/kWh Aurora pays" figure

This is Aurora Energy’s regulated Pricing Methodology (1 April 2024, RY25), the Commerce Commission Information Disclosure that RT_235 / RT_359 sought — the document the AMP OT_109 said would carry the Control Period Demand (CPD) figures. It confirms the CPD tariff structure and the Upper Clutha/Wānaka CPD export-credit trial (from 1 April 2024) that sits under Aurora’s solarZero DER case. But it contradicts the secondary figure in OT_066: Aurora “does not make payments to any owner of distributed generation” (para 185). The CPD credit is a demand-charge reduction — 50% of CPD-period export is netted off the customer’s average CPD kW, lowering the CPD price (¢/kW/day) billed — not a /kWh payment**. There is **no "1.50/kWh” and no “80 hrs/yr” anywhere in the document. Read verbatim via pdftotext -layout → data_quality: verified.

Summary

Aurora Energy Limited’s Pricing Methodology (dated 1 April 2024) is the electricity distributor’s mandatory Pricing Methodology Disclosure under the Commerce Commission’s Electricity Distribution Information Disclosure Determination, setting the delivery prices that apply from 1 April 2024 (pricing year RY25). Aurora’s network is served from five Grid Exit Points across three pricing areas — Dunedin, Central Otago & Wānaka, and Queenstown — and the document sets out how Aurora allocates its Commerce-Commission-regulated allowable revenue ($158.1m for RY25) to pricing areas, load groups, and price components, as it transitions to cost-reflective pricing (mild time-of-use from 1 April 2024, fully cost-reflective by RY27).

For Neobiome Intelligence the load-bearing content is the Control Period Demand (CPD) tariff — the mechanism the RT_235 / RT_359 value cell was chasing, and the tariff that sits under Aurora’s Upper Clutha solarZero DER flexibility case (OT_109). The document delivers three NI-critical findings. (1) A correction. Aurora explicitly “does not make payments to any owner of distributed generation” (para 185); the secondary/advocacy claim in OT_066 that Aurora “pays … ~1.50/kWh" for CPD export is therefore **not an Aurora-published tariff**. **(2) The real mechanism.** Aurora is trialling (from 1 April 2024, Upper Clutha/Wānaka only) a **CPD credit scheme**: 50% of the kWh a consumer exports during CPD periods is included in the calculation of their **average CPD kW**, which *reduces* the CPD demand charge (¢/kW/day) their connection pays. The value of exporting at peak is thus a **reduced demand charge on the customer's own bill**, not a payment — and its implied /kWh depends on the CPD price, the number of Control-Period days, and the 50% credit factor (a derivation for the engine, not a headline rate). (3) A second DSO capacity-value anchor. Aurora’s long-run marginal cost (LRMC) of peak capacity — **107/kW (Dunedin), 455/kW (Queenstown), 882/kW (Central Otago & Wānaka)** — is a South-Island counterpart to Orion's 77/kVA/yr LRAIC (OT_125) for bounding the national “value of peak battery to network” range (⚠ units differ — see relevance).

Key claims

- claim: "Aurora Energy does not make payments to any owner of distributed generation. (Verbatim, para 185, in the Distributed Generation section.) The DG connection charge is a charge levied ON generators (return on investment + depreciation + maintenance of the assets used to convey the DG's electricity); Table 12 lists current DG connection charges (e.g. Generator 1 at Halfway Bush GXP, 75 MW installed, $156,625). Small-Scale Distributed Generation (SSDG) 'sits behind load, normal delivery prices apply according to the installation's connection capacity'; SSDG owners on a residential connection 'can avoid the full retail costs of energy (per unit), including the delivery prices', and on a General connection 'can avoid a significant proportion of the distribution and pass-through CPD prices' — i.e. the value to a solar/battery owner is AVOIDED delivery charges (including the avoided CPD demand charge), not a payment."
  source_location: "Section 9 Distributed Generation — para 165–166 (SSDG, p.48); para 185 + Table 12 (p.50–51)"
- claim: "CPD credit scheme (the Upper Clutha/Wānaka flexibility mechanism), verbatim: 'For the year commencing 1 April 2024 we will be trialling a CPD credit scheme for consumers in the Upper Clutha and Wanaka areas who are able to provide network support during CPD periods. The scheme will operate by including 50% of the kwh exported during CPD periods in the calculation of average CPD kW for the year.' Eligibility criteria: installation is in the Upper Clutha / Wanaka area; is at least 69 kVA of connected capacity; is half-hourly metered; and is capable of exporting during CPD periods. 'Eligibility … is at the sole discretion of Aurora Energy and is available on a trial basis for the year commencing 1 April 2024.' The credit lowers the customer's average CPD kW, which reduces the CPD demand charge (¢/kW/day) billed — it is not a $/kWh payment."
  source_location: "Section 3.8.4 Control Period Demand Price — para 95 (p.33)"
- claim: "Control Period Demand definition and timing. 'The CPD price recovers costs associated with zone substations and sub-transmission lines and cables, which are sized for system peak loads.' CPD (kW) is the energy used at the installation while Aurora is managing demand, accumulated over the Control Period and divided by its duration to give average power demand; each installation's CPD is set at 1 April to the average of previous-winter CPD kW and prior-year chargeable CPD kW. 'The Control Period is likely to occur on cold winter days, and to last typically for two to three hours (but could last for up to ten hours on occasions). It is most likely to occur on approximately 20 to 50 days during the May to September period, with most activity during June, July and August. Control periods will be signalled via ripple control.' (⚠ No single 'CPD hours/year' figure is stated; ~20–50 days × typically 2–3 h implies roughly 40–150 h/yr, up to more with 10-hour events.)"
  source_location: "Section 3.8.4 Control Period Demand Price — para 91–93 (p.32–33)"
- claim: "Aurora's long-run marginal cost (LRMC) of peak capacity and the resulting time-of-use (ToU) peak signals, by pricing area (Table 11). LRMC ($/kW): Dunedin $107; Central Otago & Wanaka $882; Queenstown $455. Calculated ToU peak signal (cents/kWh): Dunedin 3c; Central Otago & Wanaka 24c; Queenstown 12c. ToU peak signal actually applied from 1 April 2024 (cents/kWh, judgement-moderated 'mild' ToU): Dunedin 3c; Central Otago & Wanaka 5c; Queenstown 4c. LRMC is computed by the Average Incremental Cost (AIC) method: AIC LRMC = (NPV(Capex)+NPV(Opex)) / NPV(Demand), with a shiftability de-rating (0 in year 1 rising to 100% by year 5). Central Otago & Wanaka has the highest LRMC, reflecting upcoming investment such as a new 66 kV line into the Upper Clutha area."
  source_location: "Section 4.1.3 LRMC Calculations for RY25 — Table 11 (p.36); AIC method para 104–108 (p.35–36)"
- claim: "CPD demand-charge price levels (Appendix A price schedules, ¢/kW/day, effective 1 April 2024; total = Distribution (D) + Pass-through (P)). Dunedin residential SH1 CPD Price = 71.10 ¢/kW/day (63.93 D + 7.17 P). Central Otago residential CC1A CPD Price = 77.29 ¢/kW/day (75.33 D + 1.96 P). Queenstown residential FR1A CPD Price = 47.77 ¢/kW/day (40.41 D + 7.36 P). These are the per-kW-per-day demand charges to which the 50% CPD export credit applies — i.e. reducing a connection's assessed CPD kW reduces the amount billed at these rates over the Control Period."
  source_location: "Appendix A Price Schedules — Dunedin SH1, Clyde/Cromwell (Central Otago) CC1A, Frankton (Queenstown) FR1A CPD Price rows (p.54–58)"
- claim: "CPD demand charges are a major revenue pillar. RY25 forecast allowable revenue is $158,101,807, an increase of $17.1m (12.1%) on RY24, giving an average price increase of 7.4%. By price component (Table 10), the CPD kW charge recovers $24.1m of distribution revenue (15.2% of total) plus $3.0m of pass-through revenue (1.9%) — together ~$27.1m of the $158.0m total (~17%). Residential fixed charge rises from $0.45/day to $0.60/day from 1 April 2024 (third year of the five-year Low Fixed Charge phase-out, completing RY27). Peak periods for ToU are 7am–12pm and 5pm–10pm, seven days a week, the same across all three pricing areas — 'longer than most other electricity distributors in New Zealand', reflecting the colder climate and longer winter peaks. For general customers Aurora recovers demand-related cost through the CPD price and 'does not use AMD [Anytime Maximum Demand] as a basis for charging.'"
  source_location: "Section 3.4 para 56 + Table 2 ($158.1m, p.20); Table 10 forecast revenue by price component (p.30); para 27 peak periods (p.11); Table 1 (AMD, p.17); para 45.1 fixed charge $0.45→$0.60 (p.18)"

Neobiome Intelligence relevance

• ⚠⚠ Corrects the “1.50/kWh Aurora pays" figure — a verified-source-only catch (D01/I01).** The RT_235 value cell sought Aurora's "~1.50/kWh peak-export reward”. That figure comes from the advocacy-authored OT_066 (Rewiring Aotearoa, “Electric Farms”), which states Aurora “pays Forest Lodge … at ~1.50/kWh". Aurora's own Pricing Methodology says the opposite: **"Aurora Energy does not make payments to any owner of distributed generation"** (para 185). So **no /kWh peak-export payment tariff exists at Aurora. Do not enter “$1.50/kWh” into an NI cell as an Aurora tariff; it is OT_066’s characterisation of the value of an avoided demand charge, not a published rate. This is exactly the primary-vs-secondary discrepancy the wiki’s verified-source-only rule exists to catch. OT_163
• The real mechanism: a demand-charge credit, not a payment (I01). The Upper Clutha/Wānaka CPD credit scheme (trial from 1 April 2024) works by including 50% of CPD-period export in the customer’s average CPD kW (para 95) — which reduces the CPD demand charge (¢/kW/day) their connection is billed. So a peak-exporting battery’s network value to an Aurora customer is a lower demand charge on their own bill, capped at 50% credit and gated to ≥69 kVA half-hourly-metered Upper Clutha/Wānaka connections. Any implied $/kWh must be derived: ≈ (CPD price ¢/kW/day × Control-Period days × 0.5 credit) ÷ kWh exported — a derivation for the engine using the cited CPD price levels (SH1 71.10, CC1A 77.29, FR1A 47.77 ¢/kW/day) and the ~20–50 Control-Period-days range, not a headline rate to read off. OT_163
• A second NZ-DSO capacity-value anchor for the national bound (D01/RT_360). Aurora’s LRMC of peak capacity — **107/kW (Dunedin), 455/kW (Queenstown), 882/kW (Central Otago & Wānaka)** — is the marginal cost of adding peak capacity, the value a reliably-at-peak resource defers. It pins the **Aurora end** of the still-open national multi-DSO bound (RT_360), alongside Orion's 77/kVA/yr (OT_125). ⚠ Units differ — do not compare directly: Aurora’s LRMC is a /kW present-value (AIC) marginal capacity cost**; Orion's LRAIC is an **annualised /kVA/year. Aurora’s much higher Central Otago figure ($882/kW) reflects a growing, remote, investment-heavy network (new Upper Clutha 66 kV line) — a higher-cost anchor than dense central-Canterbury Orion, and directionally consistent with remote networks carrying higher peak-capacity value. OT_163
• Grounds the OT_109 Upper Clutha DER case with its tariff (I01). OT_109 documented the solarZero solar-battery + hot-water flexibility case and the 33 MVA (winter, N-1, voltage-limited) constraint it defers, but not the tariff. This page supplies the tariff instrument that sits under that case (the CPD structure + the Upper Clutha/Wānaka CPD credit trial), completing the case → mechanism → tariff chain. The value driver is unchanged: a peak-shaving/peak-export battery earns network value only at coincident (cold-winter, ripple-signalled) peak. OT_163

Feeds d01_renewable_energy_storage and i01_financial_economic_sufficiency.

Research targets

Resolved

• RT_359 (RESOLVED → this page). Aurora Energy Pricing Methodology (1 April 2024) — the Commerce Commission Information Disclosure that carries Aurora’s Control Period Demand (CPD) tariff structure, the document RT_359 sought. Retrieved and read verbatim. Finding (with correction): the CPD structure and the Upper Clutha/Wānaka CPD export-credit trial are confirmed (para 91–95), but the hypothesised ”~1.50/kWh reward rate, ~80 CPD hrs/yr" is **not** an Aurora tariff — Aurora makes no DG payments (para 185); the value is a **50% CPD-kW export credit** (a demand-charge reduction), and the Control Period is ~20–50 days May–Sept, typically 2–3 h (up to 10 h), with no stated annual-hours figure. The numeric value cell (RT_235's original ask) is therefore **answered as a mechanism, not a single rate** — the implied /kWh is an engine derivation from the cited CPD price levels, not a retrieval gap.

Research gaps

• (continues the EXISTING RT_360 gap — do NOT open a duplicate) National bound: whether NZ DSOs beyond Orion and Aurora publish comparable coincident-peak / non-network / flexibility value rates, so NI can express a national “value of peak battery to network” range. This page pins the Aurora end with LRMC 107–882/kW; annotate RT_360 with this source_id rather than raising a new RT. ⚠ Note the unit mismatch vs Orion (/kW AIC present value vs /kVA/yr annualised) when composing the range.

Notes

Primary regulated information-disclosure document (Aurora Energy Limited Pricing Methodology, dated 1 April 2024, ~79 pp incl. Appendices A–G), read verbatim via pdftotext -layout — every quantitative claim traces to a numbered paragraph, Table, or Appendix → data_quality: verified. Directors’ certificate at Appendix G. Filed as source_type: other (a DSO’s own regulated pricing document, parallel to Orion’s Pricing Methodology OT_125 and Aurora’s AMP OT_109), not regulatory (reserved for EA/ComCom Code instruments such as REG_005). Retrieval provenance: none required — this is an authoritative Aurora Energy Information Disclosure PDF, not an AI-prepared artifact.

⚠⚠ contested: true / contradictions: [ot_066_rewiring-electric-farms-2024] — the load-bearing finding. This primary contradicts OT_066’s key_claim that Aurora “pays Forest Lodge for exporting during Control Period Demand hours … at ~1.50/kWh — ~12,000/yr”. Aurora’s Pricing Methodology states Aurora does not make payments to any DG owner (para 185); the mechanism is a 50%-of-CPD-export credit against the customer’s average CPD kW (para 95), i.e. a reduced demand charge on the customer’s own bill, not a payment. The “$1.50/kWh” is best read as OT_066’s (or Forest Lodge’s) estimate of the effective value of that avoided demand charge for one specific ≥69 kVA half-hourly-metered Upper Clutha connection — plausible as a derived value but not an Aurora-published rate, and not to be entered into NI as one. The OT_066-attributed bullets on D01/I01 are left recording what OT_066 said; the correction is carried in the NEW OT_163 bullets and here.

⚠ No “80 hrs/yr” figure exists. OT_066 / RT_235 cite “~80 CPD hrs/yr”; the Pricing Methodology gives Control Periods on ~20–50 days (May–Sept), typically 2–3 h each (up to 10 h) — an implied ~40–150 h/yr range, no single stated figure. Any NI use of a CPD-hours number must carry that range, not a point estimate.

⚠ Unit mismatch in the network-value anchors (do not compare naively). Aurora LRMC = /kW via AIC (a present-value marginal capacity cost); Orion LRAIC = /kVA/year annualised (OT_125). They are not the same unit; a national “value of peak battery to network” range (RT_360) must reconcile them (annualise Aurora’s, or present both with their unit basis) before quoting a single band.

Connections

Links to

Sources (4): OT_066 · OT_109 · OT_125 · REG_005

EDT domains (1): D01: Renewable Energy & Storage Systems

SSI indicators (1): I01: Financial & Economic Self-Sufficiency

Referenced by

EDT domains (1): D01: Renewable Energy & Storage Systems

SSI indicators (1): I01: Financial & Economic Self-Sufficiency