Source
https://www.oriongroup.co.nz/assets/Our-story/Pricing/Orion-pricing-methodology-2024.pdf — original source (opens in a new tab; the file is not redistributed)
Orion New Zealand Ltd (2024) — Methodology for Deriving Delivery Prices (1 April 2024)
Orion's regulated Pricing Methodology Disclosure (issued 29 Feb 2024) — the PRIMARY source behind the **
77/kVA/year** coincident-peak long-run average incremental cost (LRAIC) that [[ot_065_rewiring-cost-of-energy|OT_065]] cites second-hand. Appendix G shows the full six-step LRAIC derivation; §7.1 sets export credits at "approximately a third" of it; and §6's standalone subsidy-free test gives Orion's own PV+battery microgrid cost estimates (0.38–0.68/kWh) as the alternative to network supply.A DSO information-disclosure document for the pricing year 1 Apr 2024 – 31 Mar 2025, covering >224,000 connections across 8,000 km² of central Canterbury. ⚠ The
77 is the **gross** network avoided cost — Orion's realised export credit is only ~1/3 of it, and scheduled credits are a fraction of a cent per kWh (0 c/kWh for PV on non-half-hour metering). ⚠ Appendix G writes "77 /kVA/year” while §7.1 writes “$77 per kW per year” — same number, unit stated loosely. Read verbatim via pdftotext → data_quality: verified.
Summary
Orion New Zealand Limited’s Methodology for deriving delivery prices (for prices applying from 1 April 2024, issued 29 February 2024) is the electricity distributor’s mandatory Pricing Methodology Disclosure under clause 2.4 of the Commerce Commission’s Electricity Distribution Information Disclosure Determination 2012. Orion owns and operates the electricity distribution network in central Canterbury (between the Waimakariri and Rakaia rivers, coast to Arthur’s Pass), delivering to more than 224,000 homes and businesses across 8,000 km². The document sets out how Orion allocates its required revenue to connection categories and derives its fixed and variable delivery charges, as it transitions over five years from consumption-based to more cost-reflective, capacity-based pricing.
For Neobiome Intelligence the load-bearing content is Appendix G, which derives Orion’s long-run average incremental cost (LRAIC) of delivering coincident peak load as 77/kVA/year** — the figure RT_233 was raised to source directly (it is quoted second-hand, with a location-specific caveat, in the advocacy-authored [[ot_065_rewiring-cost-of-energy|OT_065]]). This is the network-deferral value a distributed resource that reliably produces at peak (i.e. a battery) could in principle displace. Three further NI-relevant blocks sit alongside it: (1) the **export credit schedule** (§7.1 + Appendix A) shows Orion pays generators only "approximately a third" of the full LRAIC, and the actual scheduled credits are tiny (0.28 c/kWh anytime, 0.95 c/kWh peak, and **0 c/kWh** for PV metered only monthly) — a concrete demonstration of the self-consumption-vs-export value asymmetry; (2) the **standalone subsidy-free test** (§6) records Orion's own estimates of the cost of a PV+battery microgrid alternative to its network, at **0.38–0.68/kWh (delivery-cost-comparable) across connection categories — a rare DSO-sourced grid-vs-off-grid crossover benchmark; and (3) a diversity figure (average residential customer peak 7.4 kW vs 2.3 kW/household diversified network peak) useful for community-scale sizing. Orion is a comparatively dense, low-cost network, so these figures anchor the lower-cost end of the NZ network-value envelope, not a remote-community case; the national bound across DSOs is already tracked as RT_360.
Key claims
- claim: "Orion derives its long run average incremental cost (LRAIC) for delivery of coincident peak load in six steps (Appendix G). Step 1 — expected peak demand: Upper HV network 680.2 MVA, Lower LV network 556.0 MVA. Step 2 — estimated replacement cost of the network: Upper HV $1,472m, Lower LV $615m, total $2,087m. Step 3 — proportion that is load dependent: $840m / $287m, total $1,127m. Step 4 — proportion of load-dependent cost sized for loadings coincident with network peaks: $702m / $85m, total $787m. Step 5 — load-dependent replacement cost per kVA: Upper HV $1,032/kVA, Lower LV $153/kVA, total $1,185/kVA. Step 6 — annualise the replacement costs and add network-average operations and maintenance: Upper HV $69/kVA/year, Lower LV $8/kVA/year, TOTAL $77/kVA/year."
source_location: "Appendix G – LRAIC (Derivation of Long Run Average Incremental Cost), p.69, Steps 1–6"
- claim: "Export credits are based on the amount of electricity injected into the network during peak loading periods; the cost of delivery during peak loading is represented by Orion's assessment of LRAIC 'which we calculate as $77 per kW per year (as noted in Appendix G)'. Because some of those costs are not alleviated by export (distribution transformers and LV systems are usually unchanged when generation is installed) and some local peaks do not align with signalled peak periods, 'the distribution credit price is set at approximately a third of the full LRAIC.' Standard credits are capped at 750 kW of generation; above that, benefits are individually assessed. A lower credit price applies to PV export recorded only as total monthly export ('non-half-hour metering'), reflecting the low average coincidence of PV output with Orion's (cold winter day/evening) network peaks."
source_location: "Section 7.1 Standard export credit prices, p.51 (⚠ states '$77 per kW per year' whereas Appendix G, p.69, gives '$77 /kVA/year' — same figure)"
- claim: "Export credit schedule effective 1 April 2024 (excl GST). Generator 0–30 kW: Anytime credits without PV = 0.00280 $/kWh; Anytime credits with PV = 0.00000 $/kWh; Peak-period credits (with or without PV, Mon–Fri 7–11am and 5–10pm) = 0.00950 $/kWh. Generator 30–750 kW, chargeable control period: real power 0.0676 $/kW/day plus reactive power 0.0222 $/kVAr/day (reactive credit quantity capped at 33% of real power, i.e. a 0.95 lagging power factor). Above 750 kW: individually assessed. Approximately 11 connections are approved for export credits."
source_location: "Appendix A – Export credit schedule, p.54 (rates + note 6: ~11 connections); note 5 (reactive cap)"
- claim: "Standalone subsidy-free test (§6): Orion estimates the cost of alternative PV/battery supply for each connection category, deducting ~12 c/kWh of avoided wholesale energy so the figure is comparable to a delivery cost. Estimated cost per kWh — Streetlighting: individual PV/Battery per light = $0.68/kWh (17,043 MWh, total cost $11,589k); General connections: subdivision-sized micro-grid of shared PV and battery = $0.48/kWh (2,421,689 MWh, $1,162,411k); Irrigation: individual PV/Battery = $0.68/kWh (140,407 MWh, $95,477k); Major customer: industrial subdivision-sized shared PV + battery + supplementary diesel = $0.48/kWh (892,340 MWh, $428,323k); Large capacity: large-scale rurally located PV with battery storage = $0.38/kWh (178,232 MWh, $67,728k). These per-kWh estimates are 'broadly based on information taken from recent economic assessments' and are Orion's standalone-cost ceiling for the subsidy-free test, not measured builds."
source_location: "Section 6 (Standalone subsidy free test) table, pp.56–57; footnote '* ...savings associated with avoiding purchasing energy at the wholesale rate of 12c/kWh has been deducted'"
- claim: "Network diversification: Orion observes an average residential customer peak of 7.4 kW, but across an entire residential suburb the network peak equates to just 2.3 kW per household — i.e. the diversified shared-network peak is roughly a third of the individual customer peak."
source_location: "Section 6 (subsidy-free discussion), p.56"
- claim: "Network scale and demand. Orion delivers to more than 224,000 homes and businesses across 8,000 km² of central Canterbury, receiving electricity from Transpower at 8 grid exit points (GXPs). Delivery (network) charges amount to approximately 27% of an average household's electricity bill (the other 73% is generation, retailer, levies/metering, transmission and GST). Network maximum half-hour demand for the 2023 winter was 660 MW (peak on 11 August 2023, up 6 MW year-on-year). Transpower's Whakamana i te Mauri Hiko projects demand could double by 2050, adding ~114 MW of load to Orion's network."
source_location: "Section 1.1, p.6 (224,000; 8,000 km²; 8 GXPs; ~27%); Section 1.3, p.7 (114 MW); Section 1.4.2, p.10 (660 MW / 11 Aug 2023)"
- claim: "Peak/off-peak delivery price schedule effective 1 April 2024 (total delivery price, excl GST, $/kWh): Peak (Mon–Fri 7:00–11:00am and 5:00–10:00pm) = 0.12020; Shoulder (Mon–Fri 5–7am and 11am–5pm) = 0.07007; Off Peak (Mon–Fri 10pm–3am) = 0.00558; Super Off Peak (3–5am) = 0.00000; Weekend = 0.03012. Major-connection demand charges ($/kVA/day, total delivery): Peak charge (control period demand) = 0.2974; Nominated maximum demand = 0.0992; Metered maximum demand = 0.0925."
source_location: "Appendix A – Price schedules, p.53 (Time-of-Use charges; Major Connections and Embedded Networks)"
- claim: "Pricing-transition mechanics. Effective 1 April 2024 Orion moved its fixed/variable revenue split from 22% fixed / 78% variable to 37% fixed / 63% variable, and raised the general fixed daily supply charge from 45 cents to 60 cents. This tracks the phase-out of the low fixed charge (LFC) regulations, which lift the regulated low-fixed-charge floor 15c→30c→45c→60c→75c→90c across 1 April 2022 to 31 March 2027, with the LFC regulations revoked on 1 April 2027. Load management via ripple control contributes approximately 50 MW of peak load deferment (peak hot water cylinder control) plus an estimated 75 MW peak reduction (fixed time control)."
source_location: "Section 3.4.2 + Table 1, p.19 (37/63 split; 45c→60c); Section 3.5, pp.20–21 (LFC schedule); Load management, p.8 (50 MW / 75 MW)"Neobiome Intelligence relevance
- The primary behind the
77/kVA network-deferral value (D01/I01).** RT_233 sought exactly this: Appendix G's six-step derivation showing Orion's coincident-peak LRAIC = **77/kVA/year (69 upper-HV +8 lower-LV). This is the gross annual network cost a reliably-at-peak distributed resource could displace — the value a peak-shaving community battery captures for the network, and the number OT_065 quotes second-hand. Holding the primary lets NI cite the figure directly, with its derivation, rather than via an advocacy source. OT_125 - ⚠ Gross LRAIC ≠ what a battery is paid — use the right layer. Orion’s realised export credit is only “approximately a third” of the full LRAIC (§7.1), and the actually-scheduled credits are far smaller again: 0.28 c/kWh anytime, 0.95 c/kWh peak, and 0 c/kWh for PV metered only monthly; 30–750 kW control-period export earns 6.76 c/kW/day. So an NI “value of peak battery to network” cell must decide between (a) the $77/kVA/yr gross avoided cost (the social/deferral value) and (b) the ~1/3 realised credit (what a NZ generator is actually paid today) — they differ ~3×. This is the concrete DSO-side counterpart to the self-consume-vs-export asymmetry OT_065 argues. OT_125
- A DSO-sourced grid-vs-off-grid crossover benchmark (D01). Orion’s own standalone subsidy-free test (§6) prices a PV+battery microgrid alternative to its network at **
0.38–0.68/kWh** (delivery-cost-comparable; add back the deducted ~12 c/kWh wholesale energy for an all-in ~0.50–0.80/kWh):0.38 for large-scale rural PV+battery,0.48 for subdivision/industrial-subdivision shared PV+battery (with diesel back-up for major load),0.68 for individual per-light / per-installation PV+battery. This is a rare distributor-authored estimate of the off-grid crossover cost and corroborates the ~100k/km line-extension / off-grid crossover economics in CR_037 — but note it is Orion’s ceiling estimate for a subsidy-free test, “broadly based on recent economic assessments,” not a costed build. OT_125 - Community-scale demand diversity (D01). The 7.4 kW individual residential peak collapsing to 2.3 kW per household at suburb (network) scale is a clean ~3× diversity factor for sizing shared community infrastructure vs summing individual peaks — directly useful when NI sizes a community connection or shared battery. OT_125
- ⚠ Location-specific — a low-cost anchor, not a remote proxy. Orion is a comparatively dense, low-cost network (Christchurch city plus Canterbury plains; delivery = only ~27% of the bill). Its
77/kVA LRAIC and0.38–0.68/kWh microgrid costs sit at the cheaper end of the NZ network-value envelope; a remote/off-grid community faces far higher network and line-extension costs. Use these as a lower bound, and bound the national range via the already-open RT_360 (whether other NZ DSOs publish comparable non-network/flexibility value rates) alongside Aurora’s Upper Clutha DER case OT_109. OT_125
Research targets
Resolved
- RT_233 (RESOLVED → this page): Orion “Methodology for deriving delivery prices” (1 April 2024), Appendix G — the primary behind the $77/kVA/yr coincident-peak LRAIC. The document RT_233 sought is now held and the derivation read verbatim (six steps, Appendix G p.69). The figure is quoted second-hand in OT_065; this page supplies the source of record. Bonus material delivered beyond the target: the export-credit schedule and the standalone PV+battery microgrid cost estimates.
Research gaps
- RT_360 (existing gap): 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 rather than a Canterbury point estimate. This page pins the Orion end of that range.
Notes
Primary regulated information-disclosure document (Orion New Zealand Limited Pricing Methodology, issued 29 February 2024, 70 pp), read verbatim via pdftotext -layout — every quantitative claim traces to a numbered section, Table, Appendix A (price schedules) or Appendix G (LRAIC derivation) → data_quality: verified. Directors’ certification (Appendix H, p.70) certifies the disclosure complies with the ID Determination. Filed as source_type: other (a DSO’s own regulated pricing document, parallel to Aurora’s AMP OT_109), not regulatory (reserved for EA/ComCom Code instruments such as REG_005).
⚠ Unit-label inconsistency in the raw: Appendix G (p.69) derives the LRAIC as 77 /kVA/year**; §7.1 (p.51) restates the identical figure as **"77 per kW per year.” Same number — kVA and kW coincide at unity power factor — but the unit is written loosely. The /kVA/year form (Appendix G, the derivation) is authoritative; recorded as such. OT_065 cites it as “$77/kVA per year,” matching Appendix G.
⚠ Gross vs realised value: the 77 is the full coincident-peak LRAIC (gross avoided network cost). Orion's actual export credit is set at "approximately a third" of it (§7.1), and the scheduled credits are a fraction of a cent per kWh — including **0 c/kWh** for PV on non-half-hour metering. Do not enter 77/kVA/yr into an NI cell as “what a battery earns”; it is the deferral value, not the payment (the layer choice — gross LRAIC vs realised ~1/3 credit — is a modelling decision for the network-value cell, not a retrieval gap).
⚠ Location-specific: Orion serves a dense central-Canterbury network; delivery charges are only ~27% of the bill. Its LRAIC and standalone microgrid costs are a lower-cost anchor, not a remote/off-grid proxy — pair with the national-bound RT_360 and the higher rural line-extension economics in CR_037.
Connections
Links to
Referenced by
EDT domains (1): D01: Renewable Energy & Storage Systems
SSI indicators (1): I01: Financial & Economic Self-Sufficiency
Sources (1): OT_163