D01: Renewable Energy & Storage Systems

Domain framework: edt_framework

Scope

On-site electricity and heat generation, storage, and microgrid management. The most robustly supported EDT domain across all four major IO frameworks (IPCC AR6 Ch. 6, IEA ETP Family 1, IRENA WETO Pillar 1, WEF ETI). CR_004

Key technologies

Solar PV, agro-PV (dual-use tracker systems), wind turbines, micro-hydro, geothermal heat pumps, battery storage (LFP, vanadium redox flow, iron-sodium flow), thermal storage, green hydrogen, smart inverters, off-grid energy management systems, P2P energy trading platforms, biomass district heating (wood chip), backup gensets, community microgrids.

Evidence

Farm-machinery energy tie (the D02/D05 diesel-vs-electric lever). Farm diesel is an imported-fuel load that electrifies into a local electric load: cropping ~100 L/ha (OT_215); electrification ~1.3 kWh electric per litre of diesel displaced, same-task basis, not the ~4 same-useful-work figure (URL_036); off-road diesel ~$2.00/L (RD_034; NZ diesel carries no excise, so pump price approximates off-road). Full detail and the per-land-use split on D02.

Heat

Biomass heat costs approximately 1/3–1/4 of gas; including capital investment, still 10–20% cheaper under normal conditions. Interview I [INT_001]
Austria: 3,000+ mini district heating plants over 35 years — mature, replicable 1–5 MW biomass heat model. Interview I [INT_001]
Economic feedstock transport radius: ~50 km for wood chip; 100 km is the practical limit. Interview I [INT_001]
Local wood chip price did not spike during 2021–22 energy crisis (unlike pellets and gas) — validates local sourcing as a resilience strategy. Interview I [INT_001]
Kaposvár reference: 15 MW biomass boiler covers 80–85% of a 42 MW district heating system’s annual heat. Interview I [INT_001]
Multi-source heat production (biomass baseload + supplementary heat pump/recovery) is now near-mandatory in Western European district heating. Interview I [INT_001]
Biomass CHP no longer viable in Europe — wind/solar cheaper per kWh; not recommended for new community projects. Interview I [INT_001]
NZ forestry produces equivalent biomass feedstock; NZ wood combustion properties require adapted boiler technology (resolved by Polytechnik after 2 years of NZ-specific research). Interview I [INT_001]
NZ heat-pump installed cost and seasonal COP (2025–26): ASHP split 760 NZD/kW_th (five NZ installer price guides plus EECA’s $4,400 average-split anchor), ASHP ducted 1,500, GSHP 2,500 NZD/kW_th (inferred from limited NZ jobs plus international cross-checks); SCOP 4.0 (ASHP) / 4.2 (GSHP). The heat-pump side of the biomass-vs-heat-pump delivered-heat comparison (CR_028). CR_026

National bioenergy & renewable-supply baseline (IEA Bioenergy 2024)

NZ bioenergy is overwhelmingly direct industrial process heat — biomass-electricity is marginal (1.5–1.7%); bioenergy = 5.6% of final energy (92% solid biomass), most used for heating in industry. Independent corroboration of the spec’s biomass = heat-only decision. OT_073
National renewable supply: 45% of total energy supply / 33% of final consumption; electricity 86.6% renewable (58.8% hydro, 19.1% geothermal), 45 TWh. Wood-processing residue ~20 PJ/yr; 38% of NZ is forest (¼ planted) — feedstock backdrop for community biomass heat. Energy-import dependency 26% overall (oil >80%). OT_073

NZ Wood Energy Strategy — supply & policy for biomass heat (MBIE 2025)

Wood energy targeted at process heat (~40% of fossil process heat replaceable by 2050); 7–8 Mt/yr of residues/low-grade logs available without impacting existing fibre users → feedstock not a regional constraint vs a community DH plant. Wood energy is a lower-value use (value triangle) → use residues, not whole logs. OT_074
airshed_restricted is the binding feasibility constraint: air-quality consenting (replacement NES-AQ by mid-2027) is the named end-user barrier for wood combustion — the documentation for the biomass feasibility_rule (§9 heat-options). Anchor case: Genesis 300,000 t/yr torrefied pellets → Huntly (displacing coal). OT_074
Biomass-heat model cells (V1+ activation): boiler installed cost **~ $1,100/kW_th** (industrial GIDI floor — community-scale likely higher; coal\tobiomass conversion ~$ 290/kW_th); wood-chip fuel $12.50–18/GJ (~5 c/kWh-fuel) at ~85% boiler efficiency → delivered heat ~5–8 c/kWh (calorific GJ/t ≈ 19.2 − 0.2164·MC). Biomass heat (~5–8c) is competitive with heat-pump heat (COP 4 on ~27c ≈ 7c) — biomass wins on high-temp/dry-year/airshed-OK rural sites, heat pumps in restricted airsheds. NES-AQ: post-2005 burners ≤1.5 g/kg + ≥65% efficiency; polluted airsheds (Waikato/Otago/Canterbury, Tasman managed) restrict solid-fuel burning. CR_028

Electricity and storage

PV is only viable with storage — duck curve has reached Hungary; without storage, capture prices collapse to economically unviable levels. Interview II [INT_002]
1:4 load-to-storage ratio: for every 1 GW of load, at least 4 GWh of storage needed; California already planning 6-hour storage systems. Interview II [INT_002]
LFP batteries at <1.5 cycles/day → 15+ year lifespan; payback 4–5 years at current prices. Interview II [INT_002]
Flow batteries (vanadium redox, iron-sodium) — zero degradation; vanadium redox scaling from 1–3 MW to 20/40 MWh; iron-sodium targets GWh scale. China leads development. Interview II [INT_002]
Dubai model: 8× PV oversizing + storage achieves 1 GW baseload overnight from daytime solar; worst-case (Stockholm insolation) ~130–140 EUR/MWh — approaching market rates. Interview II [INT_002]
Household-scale battery storage costs 2–3× more per unit than industrial scale; coordination burden outweighs decentralisation benefit at community scale. Interview II [INT_002]
Grid connection recommended as backup even for self-sufficient communities — isolated networks are most vulnerable (Texas, Spain, Australia). Interview II [INT_002]
Wind turbines now have bird/bat detection sensors — remaining environmental concern is aesthetic, not biological. Essential at this latitude; solar alone insufficient. Interview II [INT_002]
Project development timelines (Hungary): storage ~1 yr; PV ~1.5–2 yr; wind ~4 yr. Construction: storage 3 months, PV <1 yr, wind 1.5–2 yr. Interview II [INT_002]
Supply-chain concentration caveat on the six headline energy technologies (background, not a calc input). For solar PV, wind, batteries, heat pumps, electrolysers and EVs — the mass-manufactured core of the D01 menu — the global market grew ~4× since 2015 to >USD 700 billion in 2023 (~half the value of all natural gas produced globally that year), China holds ~70% of global manufacturing by value, and clean-tech is only ~1% of the ~USD 24 trillion global goods trade but growing fast. A supply-resilience flag for a self-sufficiency framing: the hardware a “self-sufficient” community depends on sits on a highly concentrated global supply chain. OT_117

Off-grid backup / firming & reliability (D20 — backstop layer)

Backstop options ranked by role: oversized LFP battery (~95% round-trip, ~NZD 1,400/kWh, firms hours→~2–3 days, clean/local); diesel genset (cheap capex, fuel ~NZD 3.0–3.5/L, mature, firms days→seasonal, fuel is an import that reduces SSI); renewable diesel HVO (drop-in, ~70–90% lower lifecycle CO₂); hydrogen power-to-power (seasonal niche only); vanadium flow battery (multi-day, costly); V2H + load-shedding/demand-flexibility (cheapest “firming”). Practical NZ stack today = diesel genset + oversized battery + demand flexibility. CR_030
Reliability is a design lever, not a fixed target: interconnected grids plan to LOLE ~2.4 h/yr (US “1-day-in-10-yr”) up to 8 h/yr (Ireland), but off-grid systems are sized to an accepted unmet-energy fraction (LPSP ~1–5%) because closing the last few percent is disproportionately costly — so designing to <100% reliability is a cheaper resilience lever than a 100%-reliability backstop, and avoids an import. CR_030
The cost of solar-only self-sufficiency is prohibitive — the NZ primary for the grid-tied/backup design premise (D18/D37): EECA’s half-hourly modelling shows NZ demand and solar are seasonally inverse (demand peaks in winter when solar is lowest), so meeting annual needs from solar+storage alone requires impractically large systems — for an 8,000 kWh/pa ICP, seasonal-storage self-sufficiency needs ~5 kW-ac solar plus a battery storing hundreds of kWh; shortening storage to a month raises the solar to 12–24 kW-ac, to a week 19–45 kW-ac. Verbatim: “it is very expensive to be self-sufficient with solar PV and battery alone… This is why off-grid power systems almost always require a backup fossil fuel powered generation.” Residential PV itself returns ~8% IRR (up to 11–12%), best at 3–5 kW-ac, comparable to utility-scale. Stronger/more-recent NZ corroboration of the CR_030 backstop logic. OT_104
HVO/biodiesel maturity (the “clean genset” question): HVO renewable diesel is a true EN15940 drop-in (no engine change) but not yet available at NZ pumps (import/fleet only; government removing barriers) — a future fuel swap, not a present option. NZ B100 biodiesel supply is fragile (Z Energy closed its Wiri plant by 2022) and ~1.5–1.8× fossil-diesel cost. CR_030
Hydrogen is research-horizon for community backup: power-to-hydrogen-to-power round-trips at only ~35–48% (vs ~95% for batteries) at ~USD 0.35/kWh, viable only for seasonal storage; NZ hydrogen activity targets production/transport, and the sole NZ community off-grid case is academic (LIT_033). CR_030
Backstop + biomass cost cells (firmed): a backup diesel genset installs at ~NZD 900/kW (NZ retail ~ $360-510/kW supply + install; intl USD 300-800/kW), and its fuel runs ~NZD 0.90-1.00/kWh — backstop power is the dearest in the system. A community **biomass boiler** is ~NZD 1,100/kW_th new (EECA Sept-2025 GIDI), but only ~NZD 290/kW_th to **convert an existing coal boiler** — the cheap retrofit route. A household **wood-stove** installs for ~$ 6k/dwelling, and pellet (ULEB) burners bypass the airshed_restricted gate. CR_031
Wood-stove CapEx, independent unit-price anchor (firms the CR_031 interim). Consumer NZ’s woodburner buying guide (updated April 2026) states appliances “range in price from $1,000 to more than$ 5,000”, with installation and building consents “usually several hundred dollars more”. With NZ installer breakdowns (flue, hearth, labour, mandatory building consent, inspection), a standard freestanding install is ~ $4,500-8,000 all-in, backing the flagged **~$ 5,000–6,000/dwelling installed** interim ( $5k conservative floor, ~$ 6k central). Unit price now sourced; the installed all-in stays grey and interim (quote-based, like the dam CapEx). URL_034
Real coal→biomass project costs (primary — EECA/Aurecon 4-case-study report): four recent NZ industrial fuel-switch projects put the CR_028/CR_031 boiler-cost cells on primary footing — capital $3.4M-$ 100M, payback 5–12 yr (with GIDI co-funding), boiler efficiency >90% net / 80% gross, handling/storage/feed ≈ half (new) to ¾ (conversion) of capital, delivery 2–3 yr from FID. Derived $/kW_th: **McCain**$ 3.4M/14 MW_th ≈ ~ $243/kW_th** (conversion, \approx the ~$ 290 figure), JS Ewers $11.5M/9-12.3 MW_th \approx **~$ 935–1,280/kW_th (new, brackets $1,100), **Fonterra Waitoa**$ 90M/30 MW_th ≈ ** $3,000/kW_th** (large greenfield, upper-bound flag). Also reinforces resilience-through-fuel-flexibility (BFB fires coal/pellets/hog fuel/sludge; retained coal store as backup). ⚠ INDUSTRIAL process heat, not community space heat;$ /kW_th derived here, not stated in the report. OT_157
Resource availability (primary Scion data): NZ’s recoverable woody-biomass residue resource is ~7.3 Mt green tonnes/yr (level-1, mid-2030s low point; “up to 7.6 Mt mid-range”), or ~3.5–4.1 Mt/yr excluding currently-marketed pulp/K-grade/sawmill-chip — against only ~0.26 Mt/yr current non-processing wood-fuel use (+~2.6 Mt/yr by the wood-processing industry). Confirms feedstock is not the binding national constraint (airshed + ~50–100 km logistics + regional concentration are). In-forest residues dominate and concentrate in Bay of Plenty; orchard residues in HB/Gisborne/Marlborough/Tasman; straw in Canterbury. OT_079
Delivered cost-supply curve (NZ primary): indicative delivered fuel cost (90 km) ranges from $3-4/GJ** (port bark, shelter belt, horticultural, MWW) and **~$ 7/GJ (wood-processing residue) up to ** $12-16/GJ** for in-forest landings/cutover chip and sawmill chip — the in-forest band corroborates [[cr_028_nz-biomass-heat-cost-fuel-feasibility-2026|CR_028]]'s$ 12.50–18/GJ, while cheaper residue streams sit well below it where locally available. NCV ~6.8–7.7 GJ/t green, rising to ~11 GJ/t after 3–4-month air-drying (~35% MC). OT_079
NZ green-hydrogen cost + role primary (the source behind LIT_033’s $8.91 benchmark).** Concept Consulting (2019) prices green H₂ at **$ 8.91/kg NZD (grid bulk-storage; = $63/GJ =$ 0.23/kWh) and $12.56/kg off-grid bulk-storage (current), and finds it loses to direct electrification across transport, process heat and home heating at any carbon price — needing ~3× the renewable energy of an EV, ~2× an electric boiler and ~6× a heat-pump space heater. Hydrogen’s only surviving niches are remote off-grid supply, 24/7 return-to-base freight, and high-carbon-price seasonal/dry-year peaking — confirming the model’s treatment of community hydrogen as a seasonal/off-grid residual, not a core generation or heating lever. All NZD (the clean-currency counterpart to the ambiguous marine costs in LIT_068). OT_122
Green-H₂ cost MODEL behind the $8.91/kg (Concept 2019, Reports 2+3 — the technical volumes of OT_122).** Report 2's Table 1 decomposes the$ 8.91/kg NZD reference into wholesale electricity $4.88 + electricity network$ 1.91 + electrolyser capex $1.03 + opex$ 0.59 + storage $0.50 per kg, on input assumptions electrolyser **$ 1,400/kW (→ $700 future), **70%** efficiency, **85%** utilisation, storage **$ 0.5/kg-H₂**, wholesale electricity $0.075/kWh**. Electricity is >75% of the cost (wholesale$ 4.88 = 55% + network $1.91) and all equipment (electrolyser + storage) only ~24% \to cheap surplus renewable electricity, not electrolyser capex, is the dominant lever. Off-grid$ 12.56/kg is driven by a ~20% solar-based electrolyser capacity factor (~15% for smaller static solar) + larger single-site storage; off-grid is only cost-effective where a grid connection would be much more expensive (remote rural spur line). Report 3 adds storage-tech costs: compressed-gas storage ~ $7,000/GJ** of capacity, pipeline **$ 1–2M/km**, metal-hydride ‘not yet ready to be used commercially’. OT_151
EU REMOTE demonstrator specs + modelled coverage (D2.2, POLITO 2018) — primary corroboration of the community-hydrogen verdict. The primary deliverable behind URL_016 specifies four off-grid/isolated-microgrid demos and models their annual load coverage. Consistent with the D01 storage architecture: an oversized battery carries the diurnal deficit while hydrogen serves only the seasonal store (Froan/Rye modelled: 61.2% RES-direct, 25.8% battery, 8.4% fuel cell, 4.5% external; Ginostra: 47.8% / 44.3% / 3.5% / 4.4%), and where a firm backstop is needed biomass beats the fuel cell (Ambornetti: 36.6% biomass vs 8.3% fuel cell, full autonomy). Design round-trip ~31.5% LHV (63% electrolyser × 50% fuel cell) before BoP/converter/auxiliary losses. The Froan driver was avoiding a new submarine cable (grid-alternative avoidance), not beating batteries — the honest niche. ⚠ EU DESIGN/MODELLED values, subsidised R&D, not NZ; keeps hydrogen a V1+/research-horizon option. OT_155

NZ national renewable-supply outlook (EECA)

NZ electricity ~80–85% renewable; solar CF ~16% (independently confirms the model’s pv_yield ~15%, RD_013); solar 240 MW / 43,641 systems (Oct 2022), <1% → 1–6% by 2035. Wind 6% → 20–34% by 2035 (largest source by 2050). Biomass 7% of primary energy, mostly industrial heat (corroborates biomass = heat-only). URL_013

NZ national electricity baseline + 100%-renewables policy (IEA 2023 Energy Policy Review — authoritative primary behind CR_012)

National electricity baseline (authoritative IEA primary — supersedes the second-hand framing in CR_012): 2021 generation 45 TWh, 81% renewable (hydro 54%, geothermal 19%, gas 11%, coal 7.2%, wind 5.9%, solar 0.5%); 2022 installed capacity 9.8 GW (76% renewable); 2021 retail prices household 212.2 USD/MWh, industry 119.0 USD/MWh; ~1 GW distributed generation (avg residential solar just over 5 kW, ~96% of installs <10 kW). The government’s aspirational 100%-renewable-electricity-by-2030 target is explicitly tempered by the IEA’s caution on “the potentially considerable costs associated with achieving the last 2-5%” (ICCC: 100% needs “overbuilding” for minimal marginal emissions) — the national-grid framing NI uses to judge when community self-generation complements rather than substitutes an already-clean grid. OT_121
The marginal capacity lever is wind + solar, and the national firming problem is the dry year: “limited options for large new hydro… a sizeable share of the required new capacity will need to come from wind and solar” — ICCC additional capacity by 2035 = 3.4 GW (BAU) / 5.1 GW (100% renewables) / 5.5 GW (accelerated electrification) on a 9.9 GW installed base; government scenarios ~4,700 GWh wind / ~620 GWh solar generation by 2030. New Zealand’s mostly run-of-river hydro has only ~3 months’ storage, so a low-inflow “dry year” pulls in fossil backup — the reliability gap the NZ Battery Project / Lake Onslow pumped hydro is meant to close (technically feasible, economics unproven, solutions in the 2030s). The macro analogue of the community-scale firming NI models with battery/biomass backstops (CR_030, CR_031). ⚠ two source-internal typos (‘445 TWh’→45 TWh, wind ‘1.04 MW’→1.04 GW) corrected in-claim. OT_121

Agro-PV

Agro-PV with tracker systems: effective land use <5% of productive farmland; “perfect synergy” with precision agriculture; technologies complement rather than compete. Interview II [INT_002]
Agri-PV panel density (kWp/ha) — EU/DE transferable proxy, no NZ value. Across a wide range of realised European agri-PV projects the installed density is 0.2-0.9 MW/ha depending on design, with the JRC adopting 0.6 MW/ha (600 kWp/ha) as its working default; named vertical-bifacial grassland systems (Next2Sun) install at ~0.4 MW/ha (400 kWp/ha). For contrast, exclusive-use (conventional) ground-mount PV averages ~0.87 MWp/ha (870 kWp/ha) globally (Bolinger & Bolinger 2022, cited by JRC), against a theoretical packed-module ceiling of ~2 MW/ha at 20% efficiency. Dual-use therefore realises roughly 45-70% of the generation density of a dedicated array on the same footprint — the density cost of keeping the land in food/grazing production. Calibrates the agripv_kwp_per_ha input. 🔴 Premise flag: the engine’s exclusive-use pv_ground_kwp_per_ha=150 sits ~5-6x below this ~870 kWp/ha reference. LIT_113
NZ agri-PV capital cost — the one NZ-grounded figure (Vaughan et al. 2023, Our Land & Water, North Canterbury sheep-and-beef). A project-modelled grazing-agrivoltaic build (elevated panels, stock grazing underneath) lands at NZD ~1,591–2,070/kWp DC (fixed-tilt; ~1,830 midpoint), i.e. at-to-slightly-above the engine’s ~NZD 1,600/kWp exclusive-use ground-PV proxy — grazing-height dual-use carries only a modest capex premium, not the ~2× of full machinery-clearance agri-PV. Calibrates agripv_cost_nzd_per_kwp. ⚠ Basis caveat: this is a DC ($/kWp) figure; the premium is much larger on an AC basis (~NZD 2,130–2,770/kWac) — confirm which basis the engine proxy uses before wiring. Project-modelled feasibility cost (with Infratec), not an audited invoice. OT_202

Shared thermal energy storage

Community shared TES (22.5–40 kWh, 8 houses) increases annual hours of zero grid import/export from 5,319 (reference: 8 × 10 kWh individual) to 6,950–6,979 — a +31% improvement with any shared storage size. Diminishing returns above 22.5 kWh minimum viable shared size (450 litres). Austin, TX study; treat as structural design benchmark. LIT_006
Pooling principle: smaller shared TES (22.5 kWh) outperforms larger distributed TES (80 kWh total) on all three metrics — zero-transition hours, 5-year accumulated cost, and payback period. Community pooling reduces total storage capacity needed while improving self-sufficiency. LIT_006
Mechanism: excess PV electricity heats shared stratified water tank (450–800 litre); demand response optimisation over full year minimises combined import cost and foregone export revenue across all community members simultaneously. LIT_006
Payback for community shared storage: 1.4–1.8 years (vs. 2.5–3.6 years for individual distributed storage) — up to 2.2 years shorter payback across discount rates of 20–30%. LIT_006

Community microgrids (NZ)

Renewables-driven community MG solutions achieve comparable LCOEs to grid-sourced electricity in NZ eco-village, island, and regional community contexts — economic viability at community scale is confirmed. LIT_002
NZ 2023 generation mix: Hydro 56.0%, Fossil Fuel 20.7% (Gas 12.3%, Coal/Gas 2.5%, Diesel 1.9%, Co-gen 4.1%), Geothermal 10.3%, Wind 9.8%, Solar PV 2.8% (MBIE 2023); Solar PV capacity grew from 44 MW (2015) to 284 MW (2022). LIT_002
Key community MG enablers: community batteries, load flexibility/demand response, EV charging management, virtual power plants (VPPs), demand response aggregators (DRAs), P2P energy trading platforms. LIT_002
Six NZ implementation impediments: regulatory barriers (grid interconnection standards, tariff structures), upfront costs, community engagement, cybersecurity/data privacy, interoperability, communication technology integration. LIT_002

NZ community microgrid LCOE benchmarks (Totarabank Eco-Village, central Wairarapa)

Totarabank is the only NZ intentional community with a peer-reviewed HOMER Pro techno-economic optimisation; grid-tied, 11.4 kW 100% solar PV; 14 inhabitants / 8 lots; central Wairarapa — the closest published community-scale analogue to Neobiome’s design context. LIT_032
Optimised community-MG LCOE = ** $0.094/kWh** baseline,$ 0.109/kWh for a design resilient to two 4-day outages/year, vs Wairarapa retail $0.34/kWh — surpasses grid parity. The NZD 0.19–0.27/kWh range is the high-resilience tail of the grid-reliability sensitivity (Figure 15), not the design point. LIT_032
At this high-wind/low-solar site (mean wind ≈6.56 m/s, solar ≈3.72 kWh/m²/d), a WT is more economically viable than PV for generation expansion, but existing PV is retained in the cost-optimum given complementary diurnal/seasonal cycles. LIT_032
Totarabank eco-village (14 inhabitants, central Wairarapa) — a second, LF-MFOA-based sizing of the same site as LIT_032: cost-optimal 17.5 kW PV + 30 kW wind + 41 kWh Li-ion battery + 9 kW inverter, sized to the existing transformer capacity, via a nested LP day-ahead dispatch inside a meta-heuristic capacity search. 2019-NZ $component cost basis: PV$ 437/375 W unit, WT $6,450/5 kW unit, battery$ 885/kWh, inverter $4,600/3 kW unit. A HOMER-style full-factorial/MILP tool underestimated the project’s net present worth by ~18%. LIT_083

Real-world validation benchmarks (CR_051 — AI-compiled, verified-source-only)

Rakiura / Stewart Island off-grid LCOE: existing diesel up to 52 c/kWh vs an optimised PV+wind+battery+H₂ microgrid ~24 c/kWh (Mohseni, Brent & Burmester 2021, Energies 6522); SDC 2024 desktop study PV LCOE **NZ $0.070-0.11/kWh**. The diesel-displacement (high-cost) end of the NZ off-grid envelope, alongside Totarabank ($ 0.094–0.109, LIT_032) and Great Barrier ($0.09–0.10, LIT_031). Primary → RT_322 (verified anchor; a Rakiura case page to follow). CR_051
Space-heat demand cross-check: Wellington modelled 2,663 kWh/dwelling/yr (Riggs, Isaacs & White 2023, BBHTC/BRANZ) — a modern figure below the 2005 HEEP-derived ~3,880 kWh (OT_037), validating CR_015’s 0.843 modernisation factor. Confirms no NZ district-heat scheme publishes per-dwelling delivered heat (RT_306 gap open). Primary → RT_324. CR_051
Whole-project community build cost — the real RT_308 anchor (OT_098, Earthsong). The Earthsong Eco-Neighbourhood (32 dwellings + common house, Ranui Auckland) cost ~ $10.73M total (2000-08 NZD) \approx$ 335k/dwelling all-in (~ $291k excl. centre; ~$ 466–536k/dwelling at 2026 CPI), houses 100% purchaser-funded. The first real NZ intentional-community whole-project cost — validates the dwellings+siteworks+communal core of the model’s CapEx headline. ⚠ Grid-connected (mains/grid/sewer), so it does NOT include the off-grid systems premium (solar/battery/water treatment/backstop) — that residual still needs a real off-grid case. OT_098
Capital-budgeting anchor for a NZ community renewable build: ROI 47.63%, IRR 54.51%, discounted payback 4.74 years against an existing-PV/grid base case; financeable by the community without subsidy. Life-cycle profitable even at the NZ$0.08/kWh feed-in tariff. LIT_032
Caveats: grid-tied only; 2020 component prices (costs materially lower now); 14-inhabitant scale not directly scalable without adjustment; load/price profiles are modelled (GREEN Grid downscaling), not metered outturns. LIT_032

NZ community microgrid LCOE — Ohakune grid-tied (4th NZ Mohseni cost anchor, 2021)

Notional grid-tied, 100%-renewable community micro-grid for Ohakune optimises to LCOE $0.08/kWh (2019 USD \approx NZ$ 0.125/kWh) — the 4th NZ Mohseni/VUW community-MG cost anchor, just above the eco-village cluster (Totarabank NZ $0.094 [[lit_032_mohseni-2020-totarabank|LIT_032]]; Great Barrier NZ$ 0.09–0.10 LIT_031) and well below Stewart Island (NZ $0.24 [[lit_033_mohseni-2021-stewart-island|LIT_033]]). Unlike those **islanded** cases it is **grid-tied** (grid = "ultimate guarantor"), and it carries a full NZ-market (Oct 2019) component-cost table — **micro-hydro$ 560/kW, PV $750/kW, battery$ 901–1,100/kWh, fuel cell $1.52k/kW, electrolyser$ 1.2k/kW** (2019 USD, ×1.56 → NZD) — a NZ-grounded cross-check on the engine’s cost cells. LIT_067

NZ community microgrid design & sharing value (Apperley et al. 2024, peer-reviewed)

NZ stand-alone sizing rules-of-thumb: solar ≈ avg daily load ÷ 4; battery ≈ avg daily base load × 3 (Motairehe: 4 kW + 22.5 kWh/site, base load 7.5 kWh/day) — an independent NZ cross-check on the PV×battery sweep. LIT_059
Intra-community sharing cut shortfall hours ~97% (Motairehe islanded, 10 houses + marae: 2,184 hrs marae standalone → 64 hrs microgrid, <1% of year) — empirical support for NI’s shared-resource pooling (D9). LIT_059
30-house grid-connected microgrid (2.5 kW + 12 kWh/house): avg grid draw −59%, peak day −33%, annual hourly peak −21%; 18.2 kWh/house/day. Peak falls least → grid fixed-cost-per-kWh rises (cf. reticulation, CR_027). LIT_059
Factory-centred town (electrified): 168 GWh/yr, 34 MW winter peak; factory process heat via high-temp heat pumps + electro-boilers (validates the heat-pump electrification coupling, D8); NetZEB (solar = annual load) + ~400 MWh battery → grid ~10% of supply. LIT_059

Motairehe fractal microgrid — the primary design paper (Apperley & Toki 2023)

The primary conference paper behind the LIT_059 / CR_012 Motairehe figures — the “~97%” headline in raw numbers. Operated STANDALONE, the marae fails to meet demand 2,184 hrs/yr and the ten houses 355 hrs combined; reconfigured as a fractal microgrid sharing the identical total resources — 110 × 400 W panels (44 kW PV) + 247.5 kWh battery across the 10 houses + marae — whole-community shortfall falls to just 64 hrs/yr (only 16 coinciding with hui), with 1,870 hrs of surplus. Direct empirical support for NI’s shared-resource pooling (D9): community sharing, not extra hardware, does the work. LIT_085
A fractal-optimised resource split + asymmetric sizing (the design LIT_059 compressed to “sharing”). Sweeping the marae’s share of the total PV+battery from 18% to 30%, a 20% allocation to the marae minimises BOTH peak and daily-average grid flow; the recommended configuration is Marae 8,800 W + 49.5 kWh vs Houses 3,520 W + 19.8 kWh (from a uniform 4 kW + 22.5 kWh standalone base sized by solar ≈ load÷4, battery ≈ base-load×3). Peak grid flow ~9.5 kW, to the marae, almost all coinciding with hui — the cable-sizing basis. A NZ community-vs-per-household resource-distribution worked example and a cross-check on the PV×battery sizing sweep (D15). LIT_085
A reticulation-cost signal that cross-checks CR_027. A preliminary costing of the LV interconnect cable sized for the ~10 kW peak found it “could have provided ~15% increased solar panel capacity across the site if no microgrid was included” — i.e. the internal wires cost on the order of ~15% of the site PV capex, “however the advantages of the microgrid interconnection… far outweigh the benefits of increased, but isolated, generation.” An independent order-of-magnitude sanity check on CR_027’s ~$8,500/household internal-reticulation line: reticulation is a meaningful but minority fraction of PV capex, and buys far more than the equivalent extra isolated PV. LIT_085

NZ off-grid microgrid — Stewart Island/Rakiura wind+tidal (marine/island upper bound, Majdi Nasab et al. 2021)

Diesel-displacement baseline + demand yardstick: SIESA supplies 408 customers on Stewart Island from five diesel generators at 62 c/kWh retail, of which 23 c/kWh is the direct diesel operating cost (67 c/kWh in the conclusion); the island draws 209 kW peak / 143.9 kW mean / 1,260,332 kWh/yr, load factor 0.69. The optimised wind+tidal+biodiesel hybrid LCOE spans 20.8–27.9 c/kWh (2W+2T lowest 20.8; optimal-renewable 2W+4T 21.3) — the high (marine/island) end of the NZ community-MG envelope, above Totarabank ( $0.094-0.109 [[lit_032_mohseni-2020-totarabank|LIT_032]]) / Great Barrier ($ 0.09–0.10 LIT_031) and level with Rakiura (~24 c/kWh LIT_033). Use as the coastal/island upper bound, not an inland design point. LIT_068
Component CAPEX (⚠ likely USD, component-only): a full off-grid stack priced in unspecified “ $" (most likely 2020-era USD) — wind **$ 500/kW** (100 kW = $50k), tidal **\approx$ 1,000/kW** (54 kW = $54k), diesel genset **$ 500/kW** ( $160k/320 kW), 1 kWh lead-acid battery **$ 154/kWh**. These are HOMER generic/adapted values and the NPC/LCOE exclude offshore construction, marine cabling and the DC–AC shore converter — treat as component-only order-of-magnitude anchors, not installed-project cost, and convert to NZD before use. LIT_068

NZ measured distributed-solar performance + a small off-grid microgrid + HV2G storage (Kerr 2024 Masters thesis)

Measured NZ industrial rooftop-solar performance (Chia Sisters juicery, Nelson): a ~16 kW array self-supplied 36.8% of factory electricity over 9 months (18,332.67 / 45,587.89 kWh), at a monitored panel conversion efficiency of 24% (1.735 kWh/m² of panel), saving ** $5,315 in nine months** (28.99 c/kWh anytime / 12 c/kWh buyback; ~6-yr monitored payback on a ~$ 30k system). NIWA Solarview over-predicted — actual generation ≈ 61% of predicted, a useful haircut factor when NI uses modelled solar yields. Rare measured (not modelled) NZ distributed-solar calibration anchor. LIT_069
A very-small off-grid NZ microgrid spec + an EV/bus storage lever: the erosion-driven PowerNet Rowallan microgrid (Southland) = 2 × 6 kW solar + 27 kWh battery + diesel backup — the very small end of the NZ community-MG ladder (LIT_031 / LIT_033 / LIT_068). Separately, an Excel HV2G proof-of-concept sizes Wellington’s electric school-bus fleet as a distributed “virtual battery”: 100% electrification (~150 buses) → ~33 MW covering >50% of localised evening peak (per-bus 350–508 kWh, 0.56 kWh/km, 20% SoC floor). ⚠ Proof-of-concept with loose units + borrowed rules-of-thumb — indicative, not validated dispatch. LIT_069

NZ community/local-energy sector baseline (Berka, MacArthur & Gonnelli 2020)

Sector scale & mix (the NZ community-owned generation baseline). A national census of 198 local-and-community-energy (LCE) initiatives (2015–2018) — by activity 43% renewable (co-)generation, 35% energy efficiency, 14% consumer-trust distribution networks, 7.5% other (peer-to-peer / microgrid / co-op gen-retail / remote battery). Operational generation projects ≈ 502 MW of community-owned generation capacity = 5.4% of total NZ installed capacity (2017); project-count mix ⅓ hydro, 24% solar, 18% geothermal, 18% wind, geothermal dominant by installed capacity. A rare sector-scale anchor complementing the national-supply baselines (OT_121) and community-MG techno-economics (LIT_002, LIT_032). ⚠ 2015–2018 snapshot, authors caveat omissions (older/unsuccessful off-grid). LIT_084
Off-grid / remote community energy — Neobiome’s exact niche. Māori indigenous orgs (7.6%, 15 initiatives) run grid-tied geothermal, geothermal heat/steam, two off-grid microgrids and marae microgeneration; all three off-grid projects are politically motivated by self-sufficiency on ancestrally owned land, both integrated microgrids at feasibility (university-partnered). Separately a rural lines operator offers solar–battery–diesel packages for customers on uneconomic/unreliable lines, with ambitions for co-operative microgrids to replace diesel back-up. Real NZ activity in the off-grid remote niche — but mostly feasibility/pilot stage (the paper’s core finding: protracted feasibility, high failure rate). Aligns with CREF resilience-microgrids (URL_015, OT_120) + island off-grid URL_012. LIT_084
Self-consumption-not-export + incumbency barrier (qualitative NZ corroboration). Practitioner: a household on ~8,000 kWh / ~ $2,000/yr** whose **5-6 kW** system saves only **~$ 300–400 because the excess “just dribbles onto the grid with pretty much no benefit” — corroborates the self-consumption-over-export economics quantified in LIT_073 / OT_104. Small generators must reach the wholesale market via a hedge contract or bilateral deals with incumbent gentailers → the market-access/incumbency barrier behind REG_004 / REG_005. Named stalls: Blueskin (NZ’s first community wind farm, consent denied 2016 / appeal lost 2017), Wellington Wind Group (Meridian declined to sell a turbine). LIT_084

Community batteries (NZ)

Community battery = 100 kWh–1 MWh embedded in local distribution network; NZ outage profile (SAIDI 4h46m, CAIDI 5h31m, SAIFI 2.35/year) implies 1–4 hour battery duration targets the dominant NZ grid failure mode. OT_001
NZ sizing analysis (15 households, Pukekohe, 14% solar CF) — 9 scenarios across 4kW/8kW/12kW solar and 120/180/240kWh battery: OT_001

Solar	Battery	Utilisation	Solar spill	Non-solar HH served
4kW	120kWh	63%	~0%	0.05
4kW	180kWh	45%	0%	0.38
4kW	240kWh	34%	0%	0.38
8kW	120kWh	100%	33%	0.23
8kW	180kWh	87–100%	12–33%	2.16
8kW	240kWh	87%	12%	4.51
12kW	120kWh	100%	54%	0.32
12kW	180kWh	100%	33–54%	2.34
12kW	240kWh	100%	33%	5.00

Optimal for 15-household NZ community: 8kW solar + 180–240kWh battery — maximises non-solar sharing while maintaining high battery utilisation and minimising spill. OT_001

Co-design rule: solar PV size and battery size must be selected together; increasing solar without increasing battery causes excess spill; increasing battery without increasing solar causes under-utilisation (below 10% in June–July for base case). OT_001
Without community battery: 36.4% of daily solar generation spilled annually; with 120kWh battery: spill drops to 2.1% (restricted to November–December only). Battery converts individual household PV into a community energy system. OT_001
Seasonal grid independence: in December–February, solar households import zero energy from the grid — full demand offset via solar generation and battery discharge. OT_001
Single large community battery outperforms equivalent aggregate of un-orchestrated behind-the-meter batteries at peak demand management — reinforces the D01 centralised storage design principle. OT_001
Scale benchmark (AU): United Energy 40× 30kW/66kWh pole-top batteries serve up to 75 households; 10–20% local peak demand reduction at Highett and Black Rock. OT_001
Fitzroy North battery hardware cost benchmark: ~ $1,100/kWh (284kWh battery, 2022); total first-of-kind project cost ~$ 1.5M including software development (>50% of funded work), connection, and artwork — software/integration overhead dominates first-deployment costs. OT_001
NZ residential BESS installed cost benchmark (MySolarQuotes 2024, all brands): average installed NZD $14,396 at 11.79 kWh =$ 1,249.79/kWh GST-incl; broader range NZD $700-$ 1,950/kWh across product mix. Rewiring Aotearoa range: NZD $700-$ 1,300/kWh installed. CR_008 Primary now held: URL_010 — ⚠ that $1,249.79/kWh average is from only 16 of 96 respondents (thin sample; RT_089 to firm at community scale). Rewiring range primary: URL_011 — batteries not ROI-positive on standard tariffs; economic only on TOU/Octopus/wholesale plans or for resilience/emissions (value = self-consumption, not arbitrage).
EECA Community Renewable Energy Fund (CREF) NZ community-scale benchmark: average NZD $88,000 installed per site** (28 kW solar + 32 kWh battery); battery-only implied **NZD$ 1,100–$1,550/kWh; ~25% EECA co-funding; ~217 sites by end-2025 — now sourced to the EECA programme primary. ⚠ grant-subsidised + resilience-scale (7–25× below a community-energy hub, CREF not openly contestable, CR_024) → a resilience-microgrid anchor, not a hub cost. Closes OT_001’s AU benchmark gap (RT_034). URL_015 CR_008
Tesla Powerwall 3 RTE boundary — 97.5% peak inverter ≠ 89% solar→battery→home full cycle. Use 89% for NZ energy yield modelling; inverter-only figures will over-estimate delivered energy by ~10% over a year. CR_008
Sungrow SBR (NZ): 12.8 kWh installed NZD $15-16k (~$ 1,170–1,250/kWh); scalable to 102.4 kWh in 4 stacks, 3-phase capable; inverter lock-in to Sungrow SH-RS/SH-RT. BYD HVM: up to 66.2 kWh per stack, ~198 kWh across 3 parallel stacks; external hybrid inverter required. CR_008
Commercial/utility-scale BESS (100–200 kWh): USD $180-$ 580/kWh ≈ NZD $300-$ 550/kWh installed — substantially below stacked residential. Meridian Ruakākā (100 MW / 200 MWh, 2025): USD $119M \approx **USD$ 595/kWh** grid-scale anchor (RT_088 resolved → OT_114, below). CR_008
Meridian Ruakākā BESS — the retrieved primary behind the CR_008 anchor (RT_088): Meridian’s 15-Dec-2022 investment-decision deck discloses NZD $186m capital investment (incl. contingency)** for **100 MW / 200 MWh** (2-hour) \to **~NZD$ 930/kWh all-in; CR_008’s “USD $119M \approx USD$ 595/kWh” is the Dec-2022 USD conversion of the same figure (×~0.64 NZD/USD), not a second data point → use NZD $186m as the primary. ⚠ Utility-scale upper bound, not a community design point, and a forward-looking decision deck (planned H2-2024, actual 2025). OT_114
Grid-connected utility-BESS template + revenue stack (D01 scaling reference): four parallel contracts — Saft BESS (battery containers + Power Electronics inverters/transformers, the “bulk” of capex), Meridian electrical (33 kV switchgear + SCADA), Meridian civil, and Transpower’s connection into the 220 kV Bream Bay substation, on a 3 ha footprint. Revenue up to $35m/yr** (price arbitrage + co-optimised 6-s FIR / 60-s SIR North-Island reserve markets + indirect); **$ 20–30m EBITDAF p.a., ** $6m opex p.a.** (mainly transmission). ⚠ The FIR/SIR + wholesale-arbitrage revenue depends on direct market participation not available at community scale; the deck pins no$ figure to any single contract. OT_114
Community-scale installation uplift over hardware ~30–60% (enclosure, BMS/EMS, grid interconnection, protection relay, commissioning) — the dominant per-kWh delivered cost driver at 50–200 kWh scale, not the cells themselves. CR_008
No NZ residential battery rebate exists (May 2026) — contrast Australia’s Cheaper Home Batteries Program; OT_001’s AU-context economics do not transfer on this dimension. NZ community battery viability depends on EECA CREF co-funding, bulk procurement, or low-cost capital. CR_008

NZ electricity baseline (2023 actual)

NZ electricity generation mix 2023: 88.1% renewable (record since 1981) — Hydro 60.5% (exceptionally high due to heavy rainfall), Geothermal 18%, Wind 7%, Solar 1%, Gas 9%, Coal 2%. More current than the 2022 figures cited via LIT_002. RD_001
Solar PV capacity reached 372 MW in 2023 (+42.1%), including NZ’s first utility-scale solar farm (Kohirā, 33 MW, Kaitaia, November 2023). Wind capacity: 1,045 MW (+10.4%, Kaiwera Downs Stage 1 and Harapaki online). RD_001
National solar-PV methodology (reusable calc input): MBIE estimates solar-PV electricity generation using an assumed annual capacity factor of 14% (panels at full output 14% of the time), scaled by NIWA sunshine-hours data for seasonal variation — a documented national sanity-check for community-scale solar yield estimates against CR_010. (2022 predecessor edition.) RD_014
Agri-PV land-sharing (Fraunhofer ISE): co-locating crops and PV on the same land raises land-use efficiency ~60–80% (LER ~1.6–1.8) — lets a land-constrained community add generation without trading away food area; ground-level (<2.1 m) vs elevated system families. German guide — NZ cost/consent a gap (RT_108). See agro_pv (D01↔D02 land lever). OT_050
Measured agri-PV land loss (footprint) by layout — a field proxy for the land-retention lever (Reher et al. 2024, Applied Energy, Belgium). Two-season arable trials measured “Land Loss (%)” = 11% for near-ground interspaced rows (vertical bifacial and horizontal single-axis tracked) and 8% for the elevated/overhead system → ~0.89 / ~0.92 of the field stays cultivable. Footprint loss (buffer/driving-safety zones) is reported separately from shading yield loss. This brackets the corpus’s prior interview figure (Interview II [INT_002], <5% → ~0.95) into a design-dependent ~0.89–0.95 retained range; Reher is field-measured, so the stronger anchor. Counterintuitively the elevated system conserves more land than near-ground rows. ⚠ Belgium proxy, no NZ value. LIT_114
Default transformation-efficiency factors (Table B.1, reusable conversion assumptions): hydro 100%, wind 100%, gas combined-cycle 55%, gas single-cycle 30%, coal 30%, oil 30%, biogas 30%, wood 25%, geothermal 15%, waste heat 15% — for any NI generation-mix energy-balance calculation. RD_014
2024 update — national renewable-electricity baseline (MBIE Energy in NZ 2025, supersedes the 2023 figures above as the current national anchor). NZ electricity was 85.5% renewable in 2024, down 2.6 points from 88.1% in 2023, as a dry winter cut hydro to 23,490 GWh (lowest since 2013) and coal generation more than tripled (+118% to 2,243 GWh); non-hydro renewables all set records (solar 601 GWh +62%, wind 3,919 GWh +22%, geothermal 8,741 GWh +13%) and total renewable generation capacity reached 8,728 MW (+7%). The “≈88% renewable grid” NI inherits from RD_001 is real but hydrology-sensitive — the grid is strongly but hydro-dependently renewable, with a coal/diesel thermal backstop that swings with the hydro year (directly relevant to grid-import-vs-local-generation weighting). RD_026
Distributed/residential solar trajectory (2024). Residential solar installed capacity (connections with and without batteries) reached 323 MW at end-2024, +29% on the year from 251 MW — the current national anchor for the pace of household/community-scale PV uptake, complementing the utility-scale plant additions (Kohirā, Naumai, Ruawai, Rangitaiki solar farms). Closest figure in the MBIE series to NI’s community-scale generation lever. RD_026
2025 update - national renewable-electricity baseline (MBIE Energy in NZ 2026, supersedes the 2024 figures above as the current national anchor). NZ electricity was 88.5% renewable in 2025 - the highest share since 1981 - recovering from the dry-2024 dip (85.5%) and passing the previous 88.1% (2023) mark, on record geothermal (9,631 GWh, +10%) and solar (959 GWh, +66%), a hydro recovery (+2.1% to 24,079 GWh despite record-low early-year inflows), and every thermal fuel falling: coal -32% to 1,523 GWh, oil -76% to 6 GWh, gas -13% to 3,538 GWh, the lowest gas generation since 1981. Renewable capacity reached 9,098 MW; the committed pipeline (1,705 MW over three years; 94% renewable, 6% BESS; solar over half at 930 MW) adds ~647 MW within a year. Read with the RD_026 bullet above, the three-year series 88.1 → 85.5 → 88.5% quantifies the hydrology swing in the grid’s renewable share. RD_039
Utility-scale solar inflection (2025). Solar capacity grew 52% in one year (545 → 830 MW) and its share of renewable generation capacity reached 9.1% (1.9% in 2020); Lodestone’s Te Herenga o Te Rā (33 MW, Jan 2025) became the first NZ solar farm connected directly to the national grid, with five further plants commissioned during 2025 (Table C1). ⚠ This edition carries no residential-solar split - the residential anchor stays RD_037. RD_039

NZ retail electricity price baseline (MBIE QSDEP — the avoided-cost input)

The NI 8,000 kWh/yr standard household is the QSDEP model customer (≈22 kWh/day, cheapest advertised low-user tariff) — RD_018 is the primary MBIE source for it, replacing the wiki-unverified CR_006 estimate (resolves RT_097; primary behind CR_009). RD_018
Pilot-region grid price, 15 Feb 2026: Richmond (Network Tasman) 37.72 c/kWh = 10.9 lines + 26.8 energy-and-other; Nelson 37.22 c/kWh = 10.5 + 26.7; NZ average 40.6 c/kWh (pilot ~7-8% below national). This is the retail price a self-sufficient community displaces — but only the energy-and-other component (~26.8 c/kWh) is fully avoidable behind the meter; lines/fixed charges persist while grid-connected (the structural input for grid-vs-off-grid breakeven, cf. RT_214/215). RD_018
Price escalation basis: the QSDEP xlsx series runs 2004→2026 (NZ retail 16.52 → 40.60 c/kWh, ~2.46× nominal over 22 yrs) — an empirical NZ retail-price escalation anchor for NI payback/NPV instead of an assumed inflator. ⚠ Advertised low-user tariffs, NOT actual paid (excludes the Network Tasman 2.6 c/kWh discount + 1.0 c/kWh trust distribution; MBIE’s sales-based series is the actual-paid counterpart). RD_018

NZ household energy end-use baseline (HEEP — primary behind the model’s ② demand split) ⚠ data to be validated: 2005-vintage, 20+ years old

National average household energy (all fuels) = 11,410 kWh/dwelling/yr (regional range 9,960 warm clusters → 13,780 cool; Dunedin/Invercargill 14,580); per-occupant 3,930 kWh/occupant/yr; average household electricity 7,800 kWh/yr. The primary source behind the figures the model carries via CR_009. Validate magnitudes against current data (EECA / HEEP2) before use — 2005 stock. OT_037
End-use split: space heating 34%, hot water 29%, other appliances 13%, refrigeration 10%, lighting 8%, range 6% (Figure 14); fuel split electricity 69% / solid fuel 20% / gas 9% / LPG 2%. This is the structural basis for the model’s ② heat_space (34%) / heat_water (29%) / elec_nonheat (~37%) split. The share structure is more durable than the absolute kWh; heat-pump + LED uptake has since shifted shares — validate. OT_037
63% of household energy is low-grade heat (<100°C) (space + water heating) — the dominant self-sufficiency target. Consumption is highly skewed: top 20% of homes use >14,450 kWh/yr (36% of all residential energy), bottom 20% <6,940 kWh/yr — a community’s per-household demand spans ~4,000–14,000+ kWh/yr. (2005 HEEP — validate.) OT_037

Rewiring Aotearoa household-model methodology (the engine behind OT_067/OT_029; firms the demand-level lever)

Occupancy-based demand scaling — the source for the NI demand_level lever. Household energy scales non-linearly with occupancy: scaling factors 1-person 0.56, 2-person 0.90, 2.7 (NZ-average reference) 1.00, 3-person 1.03, 4-person 1.07, 5+-person 1.37 (exponential fit to AER Climate-Zone-6 benchmarks, normalised to the 2.7-occupant NZ household). This validates the NI multipliers almost exactly — typical 1.00 = the 2.7-occupant reference, frugal 0.70 ≈ a 1.5–2-person household, high should be ~1.37 — so demand_level can be re-sourced to OT_070 (was “assumed”). OT_070
Non-heat appliance baseline 7.24 kWh/day ≈ 2,643 kWh/yr (other electronics 4.05 + other cooking 2.85 + space cooling 0.34) — corroborates the model’s elec_nonheat_hh 2,680. Per-machine cross-checks: heat-pump COP 4.08 (vs the model’s conservative cop_air 3.5), water-heat HP COP 3.67, induction cooktop 0.75 kWh/day. Tasman regional heat multiplier 0.78 and solar capacity factor 15.0% (≈ RD_013’s 1,389 kWh/kWp/yr). OT_070
Battery RTE 0.95 (5% losses; 1 cycle/day, 15-yr life) — a second NZ-context datapoint vs the model’s 0.90 (RT_222); RA also does NOT model battery-without-solar (no arbitrage). MfE emissions factors (kgCO₂e/kWh): electricity 0.074, natural gas 0.201, LPG 0.219, wood 0.016, petrol 0.258, diesel 0.253 — the basis for a future NI emissions layer. ⚠ The underlying appliance dataset is the AU/NZ Residential Baseline Study 2021 (next ingest, closes RT_237). OT_070

RBS2.0 — the methodology behind the RBS appliance dataset (provenance for OT_070/RT_237)

The Residential Baseline Study 2.0 (EnergyConsult for the Australian Dept of Industry, Science, Energy & Resources; 2020) is the bottom-up engineering model — AEC = Stock × UEC, ~129 products, AU + NZ (NZ = 1 of 9 regions), projections to 2040 — that supplies the appliance energy OT_070 draws on. Its time-of-use method proportions annual energy to a typical day (season × weekday/weekend) then over 24h via a load profile summing to 1.0 (default season splits Summer 0.247 / Winter 0.252 / Shoulder ~0.25); hourly vs ½-hourly differs <8%. RBS2.0 adds battery storage + EV as products. ⚠ Load-profile data is Australian-sourced (CSIRO / Solar Analytics / Sustainability Victoria) — provenance/method for NI, not a NZ diurnal-shape source (use RD_019 for that). OT_071
The RBS1.0 Technical Appendix (EnergyConsult, 2015) — the data-provenance companion to OT_071 — documents that NZ figures are largely borrowed from Australia (“usage assumed to match Australian usage”; NZ space-conditioning “approximate at best”), the caveat that qualifies every RBS-derived NZ appliance figure and hence the RA→OT_070 chain. The genuinely-NZ sources it rests on: BRANZ HEEP SR155 (2006), Burgess et al (2010) lighting, Statistics NZ QuickStats heating fuels, BRANZ SR240, and Sustainability House AccuRate modelling across 6 NZ climate zones including Nelson/Marlborough (the Lower Moutere pilot zone). Usage constants: dishwasher 200 / washer 229 cycles/yr, lighting 1.4 h/lamp/day, 14-yr cooking life. ⚠ 2015 vintage, RBS1.0. OT_072
RBS 2021 NZ Output Tables (the dataset behind OT_070/071/072; resolves RT_237) — modelled NZ energy per dwelling, 2021 (all fuels, kWh): electricity 7,172 (~7,900 per occupied household after netting out unoccupied dwellings — cross-checks CR_009 7,088 / HEEP 7,800); by end-use Appliances 2,541 / Cooking 660 / Lighting 389 / Space conditioning 3,011 / Water heating 2,800 / Transport 33. RBS Appliances 2,541 ≈ the model’s elec_nonheat_hh 2,680 ≈ RA’s 2,643 — closing the loop on RA’s appliance baseline. Trends to 2040: LED lighting collapse, EV-transport rise, insulation-driven space-heat fall. The per-end-use/fuel structure is the natural spine for an optional bottom-up appliance-level demand build. ⚠ AU-usage-anchored modelled averages over occupied+unoccupied dwellings (OT_072), not NZ metering; RBS GHG elec factor 0.15–0.24 dated vs MfE 0.074. RD_020
RBS2.0 Power Demand by Time of Use (the demand-SHAPE companion to RD_020; resolves RT_226) — NZ hourly electricity demand by end-use, GREEN-Grid-rooted (Otago/EECA 2014–2018, same NZ-measured root as RD_019, not the AU load data). NZ 2021 3-slice (solar 09-15 / peak 17-21 / night): all-season weekday 0.207 / 0.275 / 0.518; winter weekday 0.180 / 0.309 / 0.511; heating-stripped weekday 0.224 / 0.282 / 0.494. Settles the contested evening peak — corroborates CR_020/RD_019 (~0.27), refutes CR_019 (0.38). Per-end-use ToU = the spine for an optional bottom-up appliance demand build. ⚠ shares GREEN Grid root with RD_019 (independent processing, not independent data); static profiles. RD_021

Per-appliance efficiency register (E3/GEMS Energy Rating — demand-side parameter layer)

Per-appliance efficiency bands from the trans-Tasman E3/GEMS Energy Rating product register (15 Jul 2026 extract; ~23,504 registered models across 8 regulated categories) — the per-product companion to the sector-level RD_007 and the household-total RD_020. Non-AC “Labelled energy consumption (kWh/year)”, min / median / max: refrigerators/freezers 46 / 277 / 666 (n=3,981), clothes washers 137 / 288 / 1,190 (n=1,427), clothes dryers 52 / 159 / 481 (n=877), dishwashers 99 / 246 / 448 (n=1,426), televisions 51 / 397 / 2,652 (n=4,979), computer monitors 17 / 82 / 500 (n=4,241), pool pumps 370 / 1,137 / 1,643 (n=662). Air conditioners carry no single annual-kWh label — seasonal TCEC/THEC by AU climate zone (cold=Canberra / mixed=Richmond / hot=Rockhampton) plus Rated AEER (cooling W/W) / Rated ACOP (heating W/W). Gives NI a defensible min/typical/best-available kWh band per appliance for a bottom-up household load profile, and a “best-available replacement” demand-reduction scenario before generation is sized. RD_025
⚠ Opt-in, self-reported register — coverage is the regulated-product market, not the installed base (“Availability Status … is based on self-reporting of the registrant and is not always accurate”, AC data dictionary); of 3,981 registered fridge/freezer models 3,797 (95.4%) list New Zealand in Sold_in. Treat as the upper bound of efficiency available to new purchases, not typical installed-stock efficiency; pair with RD_020 for NZ ownership/penetration. Extract does NOT include the lighting or hot-water/water-heater categories — hot-water/water-heater now delivered by RD_028 (below); RT_149 kept open for lighting only. RD_025
Electric hot-water-cylinder standby-loss band — the electric-water-heater category of the same E3/GEMS Energy Rating register (1,469 registered models), the sibling extract to RD_025’s 8 categories that closes the hot-water residual it left open. ⚠ Schema differs: no annual-kWh column for water heaters — the efficiency metric is declared standing (standby) heat loss (units inferred kWh/24h per AS/NZS 4692.2; no data dictionary in the extract). Standing loss min 0.38 · median 1.86 · max 3.86, scaling monotonically with tank size (median 1.06 at ≤50 L → 2.92 at >315 L). Gross storage capacity min 9 · median 180 · max 600 L; 95.0% (1,395/1,469) are mains-pressure (unvented). Gives NI the always-on standby baseload for the dominant residential end-use (water heating ≈29% of all-electric household electricity, above) — the standby component only, paired with a draw-off/demand assumption for the total hot-water load. ⚠ Opt-in, self-reported (new-purchase efficiency band, not installed stock). RD_028

EECA EEUD 2024 vintage — national residential demand baseline (successor to RD_007)

Residential demand-mix refresh (2024 data year). 2024 residential energy 86.75 PJ (all fuels); residential electricity 50.4 PJ (58.1% of residential), of which water heating 26.7% + space heating 20.3% = 47.0% — the heat-pump-conversion / shiftable-load envelope NI already uses. End-use shares are the held-constant 2021-RBS modifier (byte-identical to RD_007’s 2023 split; Wood/Solar/Geothermal residential cells are flat GDP-scaled placeholders — not a trend), so the growth is in absolute totals: residential electricity 49.5 → 50.4 PJ within this vintage (⚠ RD_007’s pre-revision 2023 value of 47.7 PJ is not splice-compatible — the back-series was re-based). Derived per-household anchor ≈ 7,184 kWh/hh/yr at ~1.95 M dwellings (up from RD_007’s ~6,790) → NI residential anchors tick up. RD_024
⚠ Back-series revision — migrate NI off the RD_007 vintage. The 2024 refresh re-bases 2017–2023: 2023 national delivered energy now 532.2 PJ (was 542.7 in RD_007), 2023 residential 85.40 PJ (was 83.6), 2023 transport 202.44 PJ (was 207.5) — the two vintages are NOT splice-compatible, so re-check any RD_007-sourced calibration cell against this vintage rather than splicing. 2024 national total 520.9 PJ (trajectory 566.6 PJ [2017] → 532.2 [2023] → 520.9 [2024]); 2024 fuel mix Fossil 66.6% / Electricity 26.9% / Renewables 6.5%. RD_024

National electricity scenarios (MBIE EDGS 2024 — validation backdrop)

NZ electricity demand grows 35–82% by 2050 (62.1 TWh Reference); peak demand rises to 9.1–12.5 GW, driven by winter-evening residential space- and water-heating electrification — the national-scale confirmation of the heat→electricity coupling the model carries via heat-pump COP. RD_017
The least-cost new generation is mostly onshore wind + solar (some hydro/geothermal) — national validation of the model’s PV+wind generation set — but new gas peakers are needed for firming in every scenario; the community analogue of that firming need is battery/backup storage (and the resilience work, RT_175–178). RD_017
Distributed solar PV connections grow ~20%/yr recently (EA EMI), with maximum uptake materially <100% of dwellings (~⅓ rentals; some unsuitable) — realistic context for community PV-adoption assumptions. Resolves RT_117 (successor to RD_005’s 2021 framework). Scope: national scenarios, not a community input cell. RD_017
Modeled vs measured self-sufficiency (calibration): a Korean solar energy-sharing community’s design-stage self-sufficiency (171%) realised only 133% over its first year (~78%), mainly because actual insolation fell short of the standard design assumption — empirical justification for running the NI frontier at P90 as well as P50 and treating modeled SS as an estimate, not a guarantee. LIT_047

National energy scenarios (TIMES-NZ 2.0 — EECA/BusinessNZ Energy Council, validation backdrop)

TIMES-NZ 2.0 is a national least-cost energy-system model run to 2060 under two scenarios — Kea (bold, government-led decarbonisation) and Tūī (continued GDP-led growth). Electricity demand roughly doubles, 144 PJ (2018) → ~270 PJ (2050), supplying 54–59% of all energy by 2050 at ~95% renewable electricity — independent national corroboration of the electrification-doubles-demand pathway also carried via RD_017 (MBIE EDGS). Scenario projections, not measured data. OT_055
Grid-scale solar > rooftop (national least-cost): the model selects grid-scale solar as more economic than rooftop PV in both scenarios. ⚠ This is a whole-system cost optimum, not a community optimum — a Neobiome community optimises self-sufficiency, resilience, avoided distribution cost and local ownership, so rooftop/community PV can be the right choice at community scale even where the national model prefers grid-scale. Frames the national-least-cost-vs-community-self-sufficiency tension; parallels the individual-PV-vs-microgrid framing in LIT_048. OT_055
Storage: 1.9 GW (Kea) / 2.9 GW (Tūī) by 2050, predominantly lithium-ion, limited pumped hydro from 2050. ⚠ TIMES-NZ does not model dry years (average-hydro only) — so it understates the dry-winter firming a hydro-dependent system needs; the community analogue is the backup/resilience sizing in RT_175–178. OT_055
Wood fuel doubles (50 → 100–115 PJ by 2050), directed mostly to process heat replacing coal/gas — independent national-model corroboration of the NI ‘biomass = heat-only’ decision and Interview I [INT_001]‘s biomass-CHP-not-viable finding. Residential gas demand ceases by 2040; hydrogen confined to a remote-agricultural-machinery niche; biofuels modest. OT_055
Efficiency as a demand-side lever: road-transport energy/distance −80% (EVs), residential lighting −70% (LED), industry +35%, agriculture +70% — reinforces demand-minimisation-before-supply. Renewable availability inputs grounded in NIWA SolarView (solar) and EMI 2009–2017 half-hourly dispatch (hydro/wind); discount rates Kea 2.5% / Tūī 5%. ⚠ 2021 vintage — the Kea Tiwai-closes-2024 assumption is superseded; shadow costs, not market prices. OT_055

Utility-scale solar economics (NZ — Miller/MBIE 2020; resource envelope + benchmark floor)

NZ utility-solar capacity factor 0.12–0.20 (single-axis tracking adds ~15%; DC:AC inverter loading 1.2; module degradation 0.8%/yr offset by 20% over-capacity). Community fixed-tilt rooftop sits at the lower end (no tracking) — a sanity bound for NI solar-yield that cross-validates the MBIE ~14% CF and CR_010. Land-use efficiency ~35 Wp-ac/m² for ground mount. OT_056
First NZ regions to become economic for utility solar: Mackenzie and Tasman Districts (transmission), and Far North / Tasman / Marlborough (distribution) — independent confirmation that the Lower Moutere pilot sits in a top-tier NZ solar resource. Distribution-connected economic capacity ~5–15% of transmission-connected. Solar resource grounded in NIWA CliFlo + SolarView and Global Solar Atlas 2.0. OT_056
Capital cost as a benchmark floor: single-axis-tracking NZ$/Wp-ac (2018) falls with scale 2.12 (1 MW) → 1.27 (200 MW), modules 30.9%→51.9% of total; benchmarked to IRENA global USD 1,210/kW (2018) → 340–834 (2030) → 165–481 (2050). ⚠ These are whole-of-utility-project costs — community rooftop PV is materially more expensive per Wp and carries no GXP/transmission economics; use the utility figures only as a floor, never as the community input. Companion to OT_055’s grid-scale-vs-rooftop national least-cost finding. OT_056
⚠ 2020 vintage — pre-dates NZ’s first built utility solar (RD_001); cost figures are 2020 forecasts. Transfer the resource envelope, degradation/loading assumptions, regional ranking and data sources; quarantine the project economics. OT_056
Ground-mount solar land footprint — NZ total-site density. Exclusive-use ground-mount PV occupies roughly 1.3–1.5 ha/MWp on a total-site basis (~650–750 kWp/ha) once setbacks, internal roads, spacing and buffers are counted: Lincoln/Massey give a 1.5 ha/MW NZ rule of thumb LIT_121, and the EPA Tauhei fast-track consent covers a 262.5 ha total site vs ~182 ha fenced/array REG_034. Bolinger & Bolinger’s global ~870 kWp/ha is the array-only footprint (packed module rows, not the whole parcel) and so is a lower bound on land take — the total-site figure is the planning number LIT_120. Synthesised in CR_059. Bears on the food-vs-energy land contention (cf. agro_pv) and on the engine’s pv_ground_kwp_per_ha=150, which sits ~4–6× below this NZ total-site density (RT_304). CR_059

National solar+wind deployment scenarios (Pimentel Pincelli et al. 2025 — empirical logistic)

Optimisation models under-call solar/wind. This peer-reviewed study’s central finding is that energy-economy optimisation models (IAMs / TIMES / EDGS-type) have systematically underestimated real solar/wind deployment — so the wiki’s OT_055 (TIMES-NZ) and RD_017 (MBIE EDGS) magnitudes should be read as conservative, especially for solar. LIT_055
Disruptive-scenario headline: solar + wind reach 72% of generation capacity by 2050 (44% solar, 28% wind); fossil electricity phased out before 2030; renewables 94.5% (REF) / 73% (DIS) by 2025. National capacity projections, not measured data. LIT_055
National distributed-solar envelope: saturation 3.2 GW (REF) → 6.7 GW (DIS), ~18%/yr growth (2023) — the rooftop/behind-the-meter band within which pilot community PV sits (pairs with OT_056 utility resource/cost and CR_011 buy-back). LIT_055
Direction of travel = centralised → distributed + community-owned. The system must shift from South Island hydro + North Island fossil peaking to distributed solar/wind near load, a bi-directional grid and prosumers; the authors explicitly endorse supporting community-owned renewable energy projects. Peer-reviewed backing for the Neobiome decentralised-energy thesis. The binding constraint is policy/consenting/public acceptance, not technology, cost or resource. LIT_055

Distribution-side injection rebate (EA 2A decision — avoided-cost-of-distribution; ⚠ minor for self-consumption)

From 1 April 2026, NZ distributors must pay negative charges (rebates) for mass-market injection at peak, based on the average LRMC of avoided peak demand ($/kW-peak/yr; zero where a pricing region has no demand growth). This is the enacted basis for the avoided-cost-of-distribution credit — a third injection-value component alongside the retail buy-back (CR_011) and distinct from the retail price baseline (RD_018). REG_005
⚠ Calibration: treat as a minor value stream for a self-sufficient community. Modelled at **~ $6/yr** for a self-consuming household battery (one cycle/day, offsetting own demand) and only ~$ 175/yr under a high-export, symmetrical-rate scenario — material only if surplus is deliberately exported at peak. NI should not weight injection revenue in a self-consumption design. Firm per-distributor c/kWh values are exogenous (Network Tasman methodology / EA LRMC guidance → RT_220). REG_005
Retail-side companion to the 2A rebate — the enacted precondition for time-varying buy-back (EA 2B/2C decision, 16 July 2025). The Authority amended the Code so every retailer with >5% market share must make available at least one time-varying pricing plan for both consumption AND injection to residential + small-business customers with a communicating smart meter — Category B retailers by 1 October 2026 (material progress by 1 July 2026), with distribution TOU billing from 1 April 2026 and retailer data + distributor billing from 1 July 2026; the rules sunset 30 June 2031. This is the regulatory anchor behind CR_011’s “1 July 2026 reform”, but it sets NO c/kWh rates — buy-back prices stay exogenous (CR_011 / URL_014); it confirms availability, not value. REG_028
Market baseline motivating the mandate: only ~19% of NZ price plans are time-of-use (unchanged over the six years of held data); apart from Contact Energy the largest retailers do not routinely offer them, most offer a single flat injection rate, and only three smaller retailers offer dynamic (time-varying) injection pricing — so NI must model the transition to time-varying buy-back (pre- vs post-2026), not assume it universal. REG_028

Off-grid electrification — individual PV vs microgrid (GIS levelized-cost method)

IntiGIS-Local (GIS / ArcGIS) maps the least-cost off-grid option per location by levelized energy cost (LEC) across individual PV, PV microgrid, and solar–diesel hybrid, accounting for the local resource and the spatial dispersion of homes (a microgrid’s distribution-line cost scales with how spread-out the dwellings are; individual systems avoid it). The directly reusable design principle: the individual-vs-microgrid choice is often marginal on cost, so community management capacity, space and maintenance should decide it — a governance as much as a cost call. LIT_048
Off-grid reliability heuristic (solar–diesel hybrid): at 50% renewable fraction, 1 day of battery autonomy suffices (diesel covers reliability); at 75%, 2 days; standalone PV sized for ~3 days of autonomy. Indicative off-grid parameters (Cuba, internationally indicative): storage ~179.4 €/kWh (85% RTE, 18-yr, 70% DoD), PV ~1,557.5 €/kW, 7% discount rate. LIT_048

Internal microgrid reticulation cost (NZ — the network the engine omits; RT_228)

The LV network that wires a 50–150-home community microgrid together (cables + service connections + distribution transformers) costs ≈ NZD 8,500/household all-in (central; range $5,500-$ 14,000), decomposable as ~ $8,000/lot underground reticulation + service connection + 1-3 community distribution transformers ($ 15–30k installed each, sized ~2–3 kVA/home → 150–450 kVA total). Per-lot is the strongest-sourced basis (published Vector/Powerco ICP schedules + BRANZ/QS guidance); per-km ( $300k/km underground,$ 80k/km overhead) is a scaling check only. CR_027
Two design cautions: double-counting trap — in a behind-the-meter grid use the civil cost (~ $5-8k/lot) *or* the EDB per-ICP fee (Vector$ 3,193–5,339/ICP; Powerco $4,800 urban/$ 9,900 rural), never both; and underground is the base case (mandated in new NZ subdivisions; overhead is ~4.5× cheaper but a rural/extended-run sensitivity only). The 5-lot threshold shifts transformer cost onto the developer for 6+ lots; an EA connection-pricing reform took effect 1 Apr 2026. CR_027
NZTA-accepted civil-rate cross-check for any distance-linear CapEx term. The Ladies Mile Detailed Business Case Estimate (QLDC Housing Infrastructure Fund, June 2018, accepted by NZTA) prices the trench-cost drivers every distance-linear energy term shares — grid line-extension, LV reticulation, micro-hydro penstock: bulk excavation $50/m³**, rock extra-over **$ 130/m³, installed buried PE100 pressure pipe ** $200-360/m** (DN160-DN355), plus a line-item 'Power Cable Installation (incl. trenching & ducting if required)'$ 10,000 LS — an independent NZTA-accepted cross-check on the CR_037/CR_027 line-cost proxies the engine uses (and the primary that brackets the micro_hydro penstock $110/m, D26/RT_286). ⚠ 2018 base, ex-GST, ex-escalation (apply CPI/CGPI, RT_368); urban-roading context. OT_113
CGPI civil-construction escalation deflator — the “apply CGPI” step for OT_113’s June-2018 civil BOS rates (RD_032, Stats NZ, verified). The Stats NZ Capital Goods Price Index, civil construction (CEPQ.S61103, base Sep-2022 = 1000) is the authoritative escalator for the ex-escalation June-2018 rates in OT_113 before they reach the D26 penstock / energy-BOS cells. Civil construction = 1101 at Mar-2026 (+3.1% YoY, +1.9% QoQ); the energy-specific sub-series energy generation, transmission & distribution works (S611031E) = 1084, +1.5% YoY. ⚠ This release only reaches back to Mar-2024, so the full 2018→2026 multiplier still needs the Jun-2018 datum from Stats NZ Infoshare (CEPQ.S61103) — RT_368 stays open on that residual. RD_032

Techno-economic modelling

HOMER (Hybrid Optimization of Multiple Energy Resources) is the established standard tool for hybrid rural energy system optimisation — simulates thousands of configurations at hourly resolution across a full year to identify least-cost designs. LIT_003
Indian village benchmark (336 houses, 1,267 MWh/year demand): Hybrid PV+wind+battery+diesel achieves COE $0.053/kWh, NPC$ 889k, capital $150,200, O&M$ 9,040/year; PV+wind+battery+biogas achieves COE $0.0524/kWh, NPC$ 857k, capital $135,000, O&M$ 9,023/year. India-context figures — use as methodological benchmark, not absolute NZ targets. LIT_003
PAU Janta Model biodigester: 1 ton/day cattle dung → 300 m³/day biogas → 1,800 kWh/day electrical output from biogas generator; 400 kW biomass generator converts 2,400 tons/year crop residue to approximately 1,342,353 kWh/year. LIT_003
Biogas viability for NZ remote communities (Conditional). Anaerobic digestion is feedstock- and climate-dependent: unheated digesters sour below ~20 °C (≈half the NZ year), so household scale is not a reliable year-round energy source; community/farm scale needs a concentrated year-round feedstock + heated digester, and even then suits process heat, not grid electricity (a NZ dairy case covered farm hot-water only; ~500-cow energy threshold vs ~450-cow NZ average). Distinct from the modelled biomass-combustion heat path; biogas is not a modelled engine cell. See anaerobic_digestion. CR_039
NZ dairy-effluent AD — verified output (heat, not electricity). Primary datapoint behind the Conditional verdict: on a 410-cow System-5 farm (Awakeri, Bay of Plenty) with a passive solid separator, anaerobic digestion produced 558 MJ/day (solids, 42-day BMP) + 176–861 MJ/day (liquid, BMP→CSTR-model) — enough to cover the farm’s ~221 MJ/day water-heating load via a tankless gas heater, but little more (liquid CH₄ 85%, ~1.3 m³ biogas/m³ effluent; ~320 kWh/day heat at 30,000 L effluent/day). NZ dairy-farm energy baseline for context: ~73,900 kWh/farm/yr, 24% for water heating (secondary, Bowler/DairyNZ 2015). Verifies CR_039’s figures; no digester capex given (economics deferred to future work). LIT_086
Biogas micro-CHP for off-grid electricity — independent techno-economic corroboration (Malawi, Robin & Ehimen 2024). A household/community fixed-dome AD + micro-CHP model (sub-kW electrical capacities, 0.04–0.62 kWe) for off-grid rural Malawi: only co-digestion in the largest shared reactor is viable (best case NPV + $8,962.58, PB ~4 yr, LCOE$ 0.06/kWh; cow-dung-alone and household-only all negative NPV). Confirms the CR_039 finding that biogas electricity needs concentrated feedstock + scale, and that per-household economics improve by sharing the reactor. Reusable literature-value conversion parameters: CHP η_elec 39% / η_thermal 45%, biogas energy content 21 MJ/m³, methane 10.49 kWh/m³, 8,000 h/yr operation. ⚠ Malawi 2023 USD — methodological benchmark, not an NZ figure; biogas remains a Conditional, not-modelled path (cf. RD_014’s default biogas transformation efficiency 30%). See anaerobic_digestion. LIT_076
Community green hydrogen — Conditional, leaning Out (corroborates CR_030). Power-to-power H₂ returns only ~30–45% (vs ~90–95% batteries), forcing ~2–3× generation overbuild; still pilot-scale with a high-pressure safety burden. It wins only for acute seasonal storage or where the grid alternative is extraordinarily expensive — the EU REMOTE Froan Island case was justified by avoiding a submarine cable, not by beating batteries. NZ policy frames H₂ as transport/industrial, not off-grid storage; verdict unlikely to flip by ~2031 (watch-list). See hydrogen_storage. CR_040 The NZ policy primary — MBIE Hydrogen Action Plan (Nov 2024) + EECA — confirms this framing (RT_274 resolved → CR_042). CR_042
Surplus generation sold at utility tariff generates $7,247-$ 7,647/year revenue; hybrid generation costs $70,877-$ 75,316/year vs grid baseline of $116,934/year — annual savings of$ 41,618–$46,057. LIT_003

Literature synthesis

EWF nexus 84-paper synthesis recommends hybrid architecture for communities: centralised electricity grid + decentralised renewables (PV + biomass) — not a binary choice between full off-grid and full grid dependence. LIT_007
Biomass economics (EWF nexus synthesis): feasibility “highly dependent on a long-term and reliable supply of sustainable feedstock”; region-wise planning required — corroborates Interview I [INT_001] feedstock radius constraint as the binding structural determinant for biomass systems. LIT_007
P2P energy sharing via community microgrids is the most cited topic in the energy community research literature (317 citations, Long et al., 2018, Applied Energy) — bibliometric confirmation that P2P trading and community battery systems are the leading frontier of energy community design. LIT_005
Across 259 rural decentralized energy case studies (1979–2024), microgrids are confirmed as the standard architecture — “any projects involved renewable energy for rural areas should decentralize its transmission networks.” LIT_004
Decentralized power generation technologies are now “more economically competitive and have created opportunities to manage infrastructure less hierarchically and more flexibly” than centralized equivalents — bibliometric validation of the D01 design direction. LIT_004
Primary adoption barriers across the rural decentralized energy literature: high upfront costs, scarce credit, and weak maintenance capacity — affordability and community capacity are the binding constraints, not technology availability. LIT_004
Dual-use agricultural solar (7.5 kWh/day per module): Aftrak system charges an electric farm tractor during the day and powers up to 5 houses from the same array — illustrates that agricultural mechanisation and community energy access can share a single solar investment, with local artisan assembly and repair training as the maintenance model. Journalistic source. URL_001
Global clean-energy manufacturing archetype (IEA ETP-2023). IEA classifies clean energy technologies by manufacturing archetype, not by generation type: mass-manufactured (factory-assembled, volume-produced, ready-to-use off the factory floor — solar PV modules, wind turbines, EV batteries, heat pumps, electrolysers, fuel-cell trucks), large-scale site-tailored (individually designed to local conditions — most CCUS, synthetic hydrocarbons, bioenergy), and bulk materials (steel, cement, aluminium). This is the authoritative narrative parent of the “mass-manufactured vs large-scale/industrial” split in RD_004’s CSV, and gives NI a citable basis for the “off-the-shelf vs bespoke” deployment distinction its D01 menu leans on (pp.94-95; glossary p.446). Methodological, not a cost cell. OT_116
Supply-chain-security caveat on the D01 hardware menu (IEA ETP-2023). For the five mass-manufactured technologies at the core of the D01 menu (solar PV, wind, batteries, heat pumps, electrolysers), the three largest producer countries hold ≥70% of manufacturing capacity each, with China dominant in all (China >70% of silica-based solar PV modules; top-15 wind manufacturers ~90% of 2021 capacity, >55% Chinese). A self-sufficiency-resilience caveat — the hardware a “self-sufficient” community depends on sits on a highly concentrated global supply chain — thesis-side context / D01 footnote, not a calculation input (p.21). OT_116

Community energy stack (Lancaster Co-housing)

Lancaster Co-housing (England, UK, est. 2006): energy from solar panels + shared biomass boiler + community micro-hydro scheme in a nearby river — three-source renewable energy stack at residential cohousing scale; supplemented by shared cargo bikes/tricycles for local transport. LIT_014

Ecovillage-scale community energy (Findhorn case)

Findhorn wind energy trajectory: first 75kW community turbine installed 1989; expanded to 4 turbines totalling 750kW (3×225kW + 1×75kW); net electricity exporter by 2006; wind provides 28% of residential energy needs — community-owned incremental build-out from single turbine to export-positive status over 17 years. LIT_012
Soillse zero-carbon cohousing (2011–2014): super-insulated triple-glazed construction; 425mm insulated block (first UK cohousing application); community biomass heating system — demonstrates full community energy stack (renewable electricity + biomass heat) at residential scale. LIT_012
Findhorn 2017: community carbon offsetting service launched to account for resident and guest travel emissions — ecovillage-scale travel carbon accounting extending the energy boundary beyond on-site generation. LIT_012

European ecovillage energy technology adoption (N=34)

PV used by 76% of energy-seeking ecovillages — most widely deployed technology; solar thermal heating 38%, biomass 35% — these three form the core community renewable energy stack across 60 European ecovillages. LIT_020
Energy storage: 43% use some form of storage (electrical 31%, thermal 20%); 65% remain grid-connected — zero-net-energy / net-supplier model is the norm; complete off-grid isolation is the minority position. 21% have achieved complete energy SS; 45% plan to achieve it. LIT_020

Eco-cell 50-year energy transition (Auckland)

Eco-cell energy phasing: biomass plant operational ~year 15–20; 4 wind turbines completed by year 20; solar panels added ~year 20–25; forest regrowth supporting biomass fuel supply by year 30–40 — multi-source renewable energy independence achieved incrementally over 50 years in an Auckland suburban context. Proposed figures are design estimates, not empirical outcomes. LIT_018

Multi-domain SS electricity and heat benchmarks (Knivsta, Sweden)

Roof PV achieves 140% (Case 1, dense), 260% (Case 2, same population larger area), 150% (Case 3, lower population) — electricity SS is achievable in all density configurations at 59.5°N; cold climate is not a structural barrier. LIT_022
Roof configurations (Case 1 contributions to annual electricity demand): south-facing roof 40%, E-W configuration 63%, façade PV 36%. LIT_022
Heat: 66% maximum (Case 1, dense) combining all available local sources — graywater heat pump 40%, commercial surplus heat 15%, biogas from blackwater 6%, biogas from food waste 5%. Single-family cases achieve 31–48%. Heat is the most constrained domain across all three cases. LIT_022
Transport biogas: 24% of vehicle fuel demand (Case 1) — blackwater biogas 14%, food waste biogas 10%; volume-constrained, lower in less-dense cases (10%). LIT_022

Aotea-Great Barrier Island off-grid microgrid case (NZ, EV-integrated)

Aotea-Great Barrier Island off-grid microgrid (3 communities, NZ) — Optimal AHA-sized stand-alone systems: Medlands (MG 1, PV+wind+battery) 209 PV + 9 batteries + 2 wind turbines, TNPC NZD 415,838; Tryphena (MG 2a, PV+battery) 796 PV + 6 batteries, NZD 411,073; Mulberry Grove (MG 2b, PV+battery) 536 PV + 3 batteries, NZD 246,999. Optimised LCOE NZD 0.09-0.10/kWh vs NZ retail NZD 0.19/kWh — up to ~69% lower; the optimistic end of the NZ community-microgrid LCOE envelope (fully off-grid, inverter cost exogenous, EV-charger cost excluded). LIT_031
NZ off-grid component cost anchors (2021 NZD): JA Solar Half Cut PERC mono PV 0.33 kW NZD 335/unit (~NZD 1,015/kWp, panel-only); Tesla Powerwall 14 kWh NZD 15,000/unit (~NZD 1,071/kWh, pack-only) + NZD 11,000 replacement + NZD 30/yr O&M; Senwei SWT 50 kW wind turbine NZD 65,000/unit; Eaton DG IP21 21 kW inverter NZD 8,000. All 2021 NZD (1 USD = 1.41 NZD); equipment-cost anchors, not installed cost — sit slightly below CR_008 installed benchmarks. Discount for post-2021 price falls (RT_162). LIT_031
PV+wind hybridisation is resilience-led, not cost-led at this site: MG 1 shows no significant seasonal solar/wind complementarity (wind near-constant daily pattern), so wind primarily diversifies the portfolio for energy security rather than reducing TNPC; PV and WT capacities are comparable. Transferable caution: do not assume PV+wind lowers cost — justify wind on resilience grounds. Converges with RD_003 diversification argument and Interview II [INT_002] grid-backup logic. LIT_031
Capital-budgeting worked example (NZ off-grid): PI 2.06-2.91%, discounted payback 7.1-8.4 years, IRR 17.53-17.93% across the three microgrid proposals at 4% real interest, 25-yr life, NZD 0.19/kWh electricity rate. Explicit PI/DPP/IRR equations (Eqs. 49-51) usable as the NI community-microgrid investment-appraisal template. LIT_031

Community PV-exchange self-sufficiency & temporal mismatch (Austin TX, method-illustrative)

Community self-sufficiency is time-window-dependent: with an equal prosumer/consumer split and no storage, the share of community demand met by prosumer PV surplus peaks at 72.5% during 12-1 p.m. but falls below 1% by 6-7 p.m. (hourly average complementarity factor 35.6%) — a single self-sufficiency figure is meaningless without a stated time window. LIT_034
Full midday community balancing (CF>100%, 11 a.m.-2 p.m.) requires at least 75% PV penetration among households; below that, prosumer surplus cannot cancel the deficit of other households even at peak generation. LIT_034
Storage sizing anchor: one Tesla Powerwall (13.5 kWh capacity, 7 kW peak) per PV household against ~15 kWh average daily generation lifts generation-hours community self-sufficiency to a ceiling of ~83% at 100% PV+battery adoption — not full autonomy. LIT_034
Demand-side load adaptation (AC setpoint increase + rescheduling deferrable EV/wet-appliance loads in the 5-7 p.m. window) substitutes for ~60% of commercial battery storage’s self-sufficiency gain — a low-capital alternative where storage is uneconomic. US summer/cooling-load values; recalibrate for NZ. LIT_034
NZ recalibration inputs for the Afzalan method (RT_172 — advanced, not resolved). Regional fixed-30°-north PV capacity factors from NIWA TMY irradiance — 0.128 (Otago/Southland) → 0.174 (Nelson), Canterbury/Christchurch 0.151 — plus eight clustered Christchurch half-hourly residential load shapes (annual use 3,162–15,102 kWh; >2,000 profiles → 8 types at 17,520 half-hours) supply the NZ demand + supply side a recalibration of this Austin self-consumption/CF method would need. But the paper computes no self-consumption ratio, community self-sufficiency ratio or complementarity factor, so RT_172’s output gap survives (Christchurch-only demand basis, partly superseded by EECA half-hourly ICPs OT_076/OT_104). LIT_073
NZ PV LCOE envelope by scale (2015 vintage — costs quarantined): utility 10.7–14.6 c/kWh and commercial 14.6–19.8 c/kWh (6% discount), residential 16.9–24.4 c/kWh (excl. the 20%-discount outliers), with the priority ordering energy efficiency (0 c/kWh) < wind (4–11) < geothermal (8–14) < PV — a community-design “efficiency first” rule. ⚠ System costs ( $3.5/W\to$ 2.0/W) and every NPV/LCOE are ~10 yr stale (NZ PV down ~70% since 2015; current community ≈ $1,600/kWp, CR_024) — transfer the capacity factors and load-shape taxonomy, not the 2015 costs. LIT_073

Canonical single-building self-consumption / self-sufficiency definition (Luthander et al. 2015, the formula LIT_034 extends to community scale)

The base metric pair the NI energy skill computes. Self-consumption = C/(B+C) (share of PV production used on-site) and self-sufficiency = C/(A+C) (share of the building’s total load met on-site), with the storage-aware overlap M(t)=min{L(t),P(t)+S(t)}; the two are linked by Eq. 7: sc/ss = total load ÷ total production — so a self-sufficiency figure is meaningless without the PV-to-demand ratio and a stated integration window (the paper fixes the standard at one year; anything coarser than sub-hourly systematically overstates self-consumption). The definitional backbone that LIT_034 lifts to the community scale. LIT_072
Two storage/DSM uplift anchors + a modelling rule (grid-connected, European, method-illustrative). A battery of 0.5-1 kWh per installed kW PV raises self-consumption +13-24 pp (non-linear; Table 5: ~+10 pp at 0.33 kWh/kW → +30-41 pp above 1.4 kWh/kW), DSM/load-shifting alone +2-15 pp, battery+DSM +29-32 pp; hydrogen round-trip ≈ 36% vs high battery efficiency (batteries for daily balancing, H₂ only for long-duration). ⚠ Encode the paper’s rule that storage round-trip / self-discharge losses must NOT be counted as self-consumed energy. Non-NZ, non-calibrated → order-of-magnitude design anchors, not NZ baselines. LIT_072

Earthsong founder energy account (INT_006, NZ urban cohousing — resolves RT_187)

Phased, affordability-bounded deployment: at build (~2000s) PV was evaluated but judged too expensive and would have priced out less-wealthy members, so the community installed solar-thermal hot water (thermosiphon, no pumps, ~60 °C) and pre-ran 16 mm cables from switchboards to roofs to enable future PV. As PV cheapened, PV is now mounted on some carports, with more planned — house-roof PV is constrained because the limited north-facing slope is mostly occupied by the solar-thermal panels. A real NZ example of designing for future generation under capital and equity constraints. Interview VI [INT_006]
Energy decisions are collective, not per-household (no individual may add PV unilaterally), and the community made a deliberate choice not to pursue off-grid autonomy: staying grid-connected in a dense-urban setting “rather than trying to be self-sufficient in a little bubble,” since off-grid economics only favour rural sites far from existing cables. Reinforces the Interview II [INT_002] grid-as-backup principle. Interview VI [INT_006]
Live design debate worth noting: An interviewee is sceptical of replacing solar-thermal with PV + heat pump (“converting one kind of energy to another and then heating water… doesn’t seem sensible”), while the community energy review group (Interview V [INT_005]) favours exactly that to free roof space for more PV — an unresolved efficiency-vs-flexibility trade-off internal to one community. Interview VI [INT_006]

Small-wind capacity factor (NZ, by region — derived estimate)

NZ small-wind CF is low and site-bound: derived per-region estimates for 1–100 kW turbines at ~20 m hub run ~0.05–0.10 in sheltered inland regions (Waikato, Tasman/Nelson 0.07–0.10, Central Otago basin) and reach 0.22–0.30 only at exposed coast/ridge sites (Wellington 0.22–0.30, Taranaki 0.18–0.26) — roughly a third to half of NZ utility wind’s ~40% CF. CR_013
Lower Moutere pilot small-wind CF ≈ 0.10–0.16 (valley/sheltered) to 0.16–0.22 (exposed ridge), ±30–40%; basin representative 0.07–0.10. Use P50 ≈ 0.10 / P90 ≈ 0.07 for the pilot wind_cf, tagged assumed (derived, not measured). Small wind is therefore marginal-to-uneconomic at the pilot — consistent with the 2013 Nelson City RE Study (~2 W/m² density; “doesn’t stack up except off-grid”). CR_013
BRANZ/Level confirm small turbines deliver ~25–30% of rated output (good-site ceiling); international year-long field trials run lower (UK EST free-standing ~19%, building-mounted <8%; only ~7.5% of 173 sites exceeded 10% CF). Vertical-axis turbines do not improve yield at low-wind sites (less efficient than HAWT; building-mount is a failure mode). CR_013
First concrete VAWT spec (uncertified manufacturer datasheet). The Aeolos-V 10kW (Aeolos Wind Energy Ltd, UK) is a 3-blade aluminium H-rotor vertical-axis turbine: 10 kW rated (12 kW max), 6.0 × 5.5 m rotor (≈33 m² swept, derived), cut-in 2.5 m/s, rated 11 m/s; the manufacturer AEP table gives 15,026 kWh @ 5 m/s → ~17% CF (derived) and 52,770 kWh @ 10 m/s → ~60% CF — inside the ~10–30% NZ small-wind band, just below the certified Bergey Excel 15 (21.8% @ 5 m/s). ⚠ uncertified marketing sheet — no Cp, no stated wind-distribution basis, no price, so it advances but does not resolve the VAWT question (RT_202); VAWTs remain the lower-yield axis at low-wind sites. DS_004
Cross-cutting distance/energy-cost synthesis behind the RT_286/288/290 figure set (CR_054, medium — provenance, no new cell). The July-2026 research draft that seeded three D01 cost targets, now the umbrella over their verified primaries. It adds the integration no single primary carries: (i) a combined micro-hydro distance term ~ $25-50/m** (PE100 penstock$ 6.8–11.2/m URL_018 + LV cable $8.3-21.7/m [[url_019_electricaldirect-lv-cable-price|URL_019]] + trench$ 90–120/m), diameter-dependent not constant — ⚠ cable excluded at ingest as reticulation double-count, live penstock rate ~ $110/m trench-dominated ([[ot_113_ladies-mile-dbc-civil-rates-2018|OT_113]]/[[cr_037_nz-rural-grid-connection-costs|CR_037]]); (ii) the **district-heat marginal-vs-full boundary NZ$ 3.5–35k/home (verified NZ hydronic fit-out $18-30k [[url_021_modserve-nz-hydronic-cost|URL_021]] vs UK network+HIU ~NZ$ 3.5–5k marginal OT_089); (iii) the small-wind m/s→CF method — Rayleigh (Weibull k=2.0) power-curve integration, CF = AEO/(rated kW × 8,760), quick rule AEO ≈ 0.01328·D²·V³ (URL_017; certified turbines DS_002/DS_001). Verified-source-only: nothing applied on this synthesis’s authority. CR_054

Heat-pump cost & seasonal COP (NZ)

ASHP: installed ~ $500-1,100/kW_th (residential split) to ~$ 700–1,300/kW_th (ducted/community); NZ-average seasonal COP ~3.5 (EECA), ranging ~2.0 (coldest: Central Otago/Southland) to >4.0 (Auckland/Northland). Pilot (Nelson/Tasman) design SCOP ~2.8–3.3 → use ~3.0 for @cop_air. Nameplate COP degrades ~20–40% in the field (oversizing, cycling, install quality). CR_014
GSHP: installed ~ $1,700-3,500/kW_th residential / ~$ 1,000–2,700/kW_th community; seasonal COP ~3.5–5.0 and far more seasonally stable than ASHP (ground/groundwater 12–16°C year-round). ~2–3× ASHP capex and site-gated (200–450 m² horizontal loop or drilling + RMA consent). Use ~$2,000/kW_th, COP ~4.0–4.5 (sourced-medium, ±30%). CR_014
NZ GSHP primary now ingested (GNS/EECA BoP RETA, SR 2024/02): two community/industrial open-loop-aquifer GSHP anchors — Whakatāne Hospital $5.61M \approx **$ 2,670/kW_th** (2.1 MW_th, >40% energy saving vs ASHP) and Whakatāne Growers $6.57M \approx **$ 1,370/kW_th** (4.8 MW_th) — bracketing the model’s $2,500/kW_th. ⚠ COP is source-temperature-driven: 2.77 @ 15 °C → 4.0 @ 30 °C (Table 5.3), so @cop_gshp 4.2 suits a warm/elevated source but is optimistic for generic ~15 °C ambient (→ RT_284). Indicative (30% contingency, open-loop) → cost cell stays medium. OT_086
NZGA base-load rule: a GSHP sized to 60% of peak heating load supplies ~97% of annual heat. CR_014
Heat↔electricity coupling: at pilot SCOP ~3.0, electrified space heat adds ~⅓ of heat demand back as electricity load (heat ÷ COP) — the cross-domain term the generation sizing must cover. CR_014

Residential space-heat demand (NZ, by region — demand driver)

NZ residential space-heat demand is low internationally (~3,220 kWh/hh/yr national avg, ~32% of household energy; UK ~12,000) due to a temperate climate, partial/spot-heating culture (85% heat the living room daily, only 24–34% heat bedrooms; 28% of homes below 16°C on winter evenings), and ~5% central-heating penetration. Range ~2,300 (Northland) to ~7,460 (Southland). CR_015
Pilot (Tasman): ~2,900 kWh/hh/yr space heat, P90 cold-year ~3,200 (uplift factor 1.10). Tagged assumed/derived (HDD-interpolated, ±25–30%). Figures are gross delivered energy (all fuels) reflecting actual under-heated behaviour — a “standard build” baseline the D17 multiplier adjusts. CR_015
Heat→electricity coupling (with CR_014): at pilot SCOP ~3.0, ~2,900 kWh space heat ÷ COP ≈ ~970 kWh electricity/hh if fully heat-pumped — the cross-domain load the generation sizing must cover (before water heat + building-standard reduction). CR_015
Primary now ingested (RT_324 target). BRANZ/BBHTC modelled a Wellington/Kelburn dwelling at 2,663 kWh/yr space heating (physics-first bottom-up: whole-house 20 °C, 1 ACH, 184 heating days May–Oct, ΔT 7.4 °C on 1909–1980 Kelburn normals, NZBC H1 basis) — a 2023-published modern anchor confirming the ~3,880 kWh HEEP-derived figure (OT_037) carries CR_015’s 0.843 modernisation discount. ⚠ This is a full-comfort DEMAND figure, not measured consumption — NZ’s spot-/under-heating culture (bullets above) means actual space-heat burn is materially lower; use 2,663 kWh as the design value for a well-served dwelling and rescale by heating-degree-days for other regions (post-2015 measured gap → RT_358). OT_106
Space vs water heat — seasonality (same source). Space heat 2,663 kWh/yr is “on par with” water heat 2,951 kWh/yr (7.3 vs 8.1 kWh/day), but space heat is strongly seasonal (monthly 340–552 kWh, +80% coldest-vs-warmest) while water heat is near-flat (212–266 kWh, +26%) — “increased energy expenditure in colder months is largely attributable to air heating”. Supports the D19 3-slice seasonal-mismatch treatment: the winter heat spike is a space-heat phenomenon. OT_106

Solar thermal hot water (NZ cost & yield)

Installed ~NZD 1,400–2,250/m² flat-plate (mid ~ $1,750/m²); evacuated-tube +15-25%; community >20 m² ~$ 1,100–1,600/m² (low conf). NZ field data shows no flat-plate vs evacuated-tube yield difference (install quality dominates) — use flat-plate for costing. CR_016
Annual yield 550–700 kWh-th/m²/yr central NZ; pilot Nelson/Tasman is NZ’s highest-irradiance zone → ~700 (range 600–850) for @solar_thermal_yield. Solar fraction ~38% avg (up to 70–95% well-designed); cuts water-heating cost up to 75% summer / 25–45% winter; BRANZ sizing ≈1 m² collector per 50–70 L cylinder. CR_016
Primary now ingested — BRANZ SR188 field study (35 solar systems, 4 centres, 2004–06): avg solar contribution 1260 kWh/yr = 38% of water-heating needs; spread driven by install quality, not technology (ANOVA p=0.98 technology, p=0.31 region) or region; avg COP 1.2 (~74% better than an electric cylinder). The @solar_thermal_yield per-m² figure (~434 avg) is this 1260 kWh/yr ÷ ~2.9 m² mean collector area — a pre-G12/AS2 real-world floor; modern well-installed systems sit higher. OT_084
Provenance, not a new yield figure (SR239, 2010). BRANZ SR239 re-analyses the same 33–35 SR188 systems (2004–06) — no new field cohort — so it does not move @solar_thermal_yield, which still rests on SR188 + CR_016; the modern-field-dataset gap (RT_282) stays open. It documents the COP measurement method behind SR188’s numbers (draw-off ÷ non-environmental electricity, standing losses excluded) and independently restates the COP anchors: electric storage cylinder COP 0.67 (~33% standing losses), a SWH at COP 1.34 needs half the energy of a standard cylinder — a second BRANZ report agreeing with OT_084. OT_105
Install quality dominates, and a cheap lever exists. Fitting a timer on the supplementary-heating element improves SWH performance by >50% (Kerr 2008, TRNSYS) — reinforcing SR188’s “technology second-order (ANOVA p=0.98), install quality first” finding NI uses to cost flat-plate generically. SR239 relocates the modern per-model performance target to EECA’s AS/NZS4234:2008 TRNSYS listings (modelled, not field) → RT_356. OT_105

Water-heating technology performance (NZ DHW, BRANZ SR488, 2025)

CO₂ heat-pump water heater (DHW duty): uses 36–46% of the grid electricity of a resistance cylinder year-round (effective COP ~2.5 in winter) — the hot-water complement to CR_014’s space-heating SCOP. The resistance DHW baseline it offsets is 8.4 kWh/d (~3,070 kWh/yr), which cross-checks HEEP’s 29%-water-heating share (~3,310 kWh/yr) — two independent NZ sources agreeing on the load. OT_038
HPWH field reality-check (NZ, BRANZ SR237, 2010). The one dedicated NZ field-monitoring dataset of heat-pump water heaters — 11 systems, Auckland/Wellington, ≥151 days — measured installed COPs of 0.53–2.00 (most integral units 1.1–1.6), far below the “up to 3 units of heat per unit of electricity” marketing premise and below SR488’s single modern CO₂ unit (~2.5). The decisive signal is draw-off dependence: a HPWH only reaches COP 1.5 when the household draws ≥140 L/day (7 of 11 monitored households used less), and dropping from a small (7.1 kWh) to extra-small (3.4 kWh) draw-off cut average COP 1.61 → 1.14 (the report’s “41% lower” is measured off the extra-small 1.14 base; on the 1.61 baseline the fall is ~29%, equivalently 1.61 is 41% above 1.14) — so HPWH savings largely evaporate for low-occupancy / low-use dwellings. Cold-climate penalty stacks on top (~27% more energy at 6 °C vs 15 °C; Invercargill ~14% less efficient year-round than Auckland). It independently restates the DHW anchors (electric storage cylinder COP 0.67; COP 1.34 = half a cylinder’s energy). ⚠ Vintage/technology caveat — these are 2010 R-134a-era integral/split units, not modern CO₂ HPWHs, so SR237 is a real-world field floor + low-draw-off warning, not the modern design COP (that stays SR488/CR_014’s ~2.5). OT_162
Solar-direct PV water heating (small dedicated PV array → cylinder element, no battery/inverter; new technology page solar_direct_pv_water_heating): cuts grid hot-water electricity to ~⅓ of reference in summer but is weak in winter (larger array needed) — a summer/shoulder load-shifter, not a year-round standalone. A cheap retrofittable ④ heat-supply option alongside heat pumps and solar thermal. OT_038
PV-first vs solar-thermal on the roof — the evidence base for the model’s V0.7.4 roof-priority ruling. IEA SHC Task 69 (April 2025): solar-thermal collectors run at ~60% efficiency vs a PV+heat-pump system (COP 3 × PV 16.7%) at >50% solar-to-water — so for a fixed roof area solar-thermal wins raw thermal yield. But PV output “can be used to meet other electrical loads and would not just serve the hot water system” (opportunity cost), and with a heat pump (NI COP 4) + falling PV cost the field has moved to PV — so the model claims scarce roof for PV first, solar-thermal fills the leftover. PV2Heat also suits “unreliable grid service, high connection costs, or low up-front capital” — the off-grid case. OT_095
No cost data in SR488 (energy-performance only) — cost-benefit cells for both DHW options remain to be sourced (new RT); the @solar_thermal_yield collector figures above are unaffected (different technology). OT_038
Option taxonomy & emissions ranking (BRANZ Bulletin 689, 2024): the six NZ water-heating families are electric (storage/continuous), fossil gas (storage/califont), heat pump (air- or ground-to-water), thermal solar, dedicated PV, and wetback — all but pure-electric/gas pairing with electric back-up. On operating emissions heat pump / dedicated PV / thermal solar rank lowest, fossil gas highest; electric resistance beats gas (grid largely renewable) but costs more to run and adds to peak (ripple-controllable). Water heating ≈ ⅓ of home energy — a third NZ source converging with HEEP (29%) and SR488 (31%). OT_041
Heat-pump refinement: ground-source > air-source efficiency (steady ~12°C source); CO₂-refrigerant units avoid high-GWP synthetics (~1,430× CO₂, ~6%/yr leakage) — an embodied-emissions point alongside CR_014’s SCOP/cost. OT_041
Trans-Tasman policy/market context (E3 Program, 2018 consultation). The joint AU/NZ Equipment Energy Efficiency (E3) Policy Framework for Hot Water Systems states water heating is ≈28% of NZ household energy, ≈33% of NZ residential GHG emissions, and 78% electricity-supplied (2014); NZ water-heating energy 16 PJ (2014) → 18 PJ (2030); electric storage is the dominant NZ system (gas instantaneous second; solar-electric sales suppressed since the $500-$ 1,000 subsidy ended mid-2012). NZ’s ≈85%-renewable grid is why electric hot water is comparatively low-emissions here. Regulatory coverage: electric-storage MEPS since NZ 2002 / AU 1999 (AS/NZS 4692:2005), gas MEPS NZ 2011 / AU 2013, but heat-pump, solar and direct-PV water heating have NO MEPS and NO labelling (PV: no product measurement standard). ⚠ Figures 2014-vintage (Residential Baseline Study) + policy-consultation framing; corroborates HEEP’s ~29% water-heating share, not a fresh calibration. OT_161
Hot-water cylinders as thermal storage / demand response (international evidence): an existing ~190 L electric cylinder already stores ~6 kWh (~73% of daily DHW) and can be controlled to shift load — a very low-cost storage resource vs Li-ion (~US$700/kWh, 2015) and the technical basis for NZ ripple control (OT_041). But the value is load-shifting (heat with daytime PV), not net storage — running tanks hotter to store more raises standby losses and on-site consumption, with the benefit going to the grid. US-context. OT_052
**Community-scale hot-water storage cost (NZ, $/L).** Premium duplex-SS DHW cylinders are NZ-published (fetchable): 500 L = NZD 7,671.82 (~15.3/L), 615 L = NZD 8,811.81 (~14.3/L) — per-litre cost declines with size (refrigeration.nz, unit price excl. install). Plain hydronic buffer / thermal-store tanks (Cooke, Central Heating NZ, Rinnai) — the cheaper tank a shared community heat loop would use — are all price-on-application, roughly ~NZD 6-10/L (unconfirmed). Advances RT_003 (the community shared-tank$ /L the household CR_038 left open); the plain-buffer figure still needs a vendor quote. CR_047

National solar specific yield by NZ region (PVGIS-ERA5, 16 regions)

Single-methodology table (1 kWp crystSi, north-facing, tilt = round(latitude), 14% loss; validated vs NIWA SolarView at Lower Moutere ~2%). Annual yield 1,246 kWh/kWp/yr (Southland) to 1,573 kWh/kWp/yr (Wellington); Tasman/Lower Moutere 1,389 — inside CR_010’s independent 1,350–1,380 band. Implied CF (yield/8,760 h) ~14.2% (Southland) to ~18.0% (Wellington); Tasman ~16.0% — every region at or above the inherited 14% national CF. Generalises ② pv_yield from the pilot to all NZ; resolves RT_138. RD_013
Winter trough is June nationwide — per-region June output (Tasman 78.4, Southland 61.7, Otago 67.4 kWh/kWp) is the binding value for off-grid/battery winter sizing; the summer:winter monthly swing widens southward (Auckland 1.74×, Tasman 1.84×, Wellington 2.06×, Southland 2.17×), so South Island designs need proportionally more storage. Caveat: PVGIS-ERA5 reanalysis, one centre/region, round(latitude) annual-max tilt (not the 40–45° off-grid winter tilt); 15/16 rows unvalidated — site NIWA SolarView run still recommended (RT_207). RD_013
Peer-reviewed satellite-solar accuracy anchor (Brent et al. 2020, VUW/Solargis). The Solar Atlas of New Zealand (Solargis on the World Bank/ESMAP Global Solar Atlas platform, ~250 m raster, MTSAT-2/Himawari-8) reproduces the NIWA Kelburn 2018 ground record to an annual GHI rMBD of 3.2% (1,269.7 measured vs 1,312.1 modelled kWh/m²), inside its stated ±4.0–5.5% GHI uncertainty and comparable to Solargis’s global ±3.1% and NZ-Lauder ±4% benchmarks — independent peer-reviewed evidence that satellite/gridded solar layers of the same class as RD_013 are accurate to ~±3% annually for NZ, adequate for coordinate-first screening. ⚠ Tabulated as GHI (kWh/m², horizontal), not PVOUT specific yield (kWh/kWp) — a dataset-accuracy cross-check, not a direct kWh/kWp validation of the RD_013/CR_010 cells. LIT_071
Winter overestimate = an explicit off-grid winter-sizing caveat. The fit is strongly seasonal — rMBD 0.6% in summer (DJF) but 8.3% in winter (JJA), up to 41.9% on a single overcast 1 July day (0.665 modelled vs 0.386 recorded kWh/m²) — because the satellite model underestimates cloud, i.e. overestimates winter GHI. Winter is the binding constraint for off-grid autonomy, so any satellite/atlas solar figure fed to NI should carry a winter haircut; corroborates the Waimea/Moutere winter-fog suppression flagged in CR_010. LIT_071

NZ regional residential demand baseline (EA EMI, year ended 31/12/2025)

Average residential consumption per connection (ICP) by regional council ranges Southland 8,131 kWh/yr (rank 1) → West Coast 5,745 (rank 16), a ~41.5% spread; the four highest are all South Island (Southland, Canterbury 8,046, Otago 7,837, Tasman 7,233, rank 4). The official region-localised load anchor for ② electricity demand — the primary behind CR_009’s regional figure; cold-region skew tracks RD_008 heat demand. Resolves RT_139/RT_094. RD_016
Per-connection consumption fell in 15 of 16 regions year-on-year (only Bay of Plenty rose +0.31%), most −0.7% to −3.0% — flat-to-declining. Boundary: per-connection regional average (not per-household/occupant; no ICP counts → not re-weightable to a national mean; solar net/gross-metering treatment unstated). RD_016

National household electrification cost anchors (Rewiring Aotearoa / EECA 2024)

Rooftop solar is the lowest-cost delivered energy for NZ homes — ~6 c/kWh (0% finance) / ~12 c/kWh (5.5%) vs ~34 c/kWh average grid (24 c excl. fixed); solar $2,000/kW, 30-yr, 15% CF. Home batteries at a tipping point: **$ 700–$1,300/kWh installed → ~17–28 c/kWh per cycle** (5,475-cycle life, 95% RTE) — matches the CR_008 band, independent peer-reviewed confirmation at household scale. OT_029
Full-household 7 kW solar + 7 kWh battery (average home, 2.8 ppl): cuts energy use 87 → 27 kWh/day, 15-yr emissions ~105 t → 4.5 t CO₂e (embodied payback ~2 yr); whole-home saving ~ $1,485/yr (grid) to ~$ 4,699/yr (solar+battery, 1% finance) vs gas+petrol. OT_029

Nelson–Tasman primary climatology (Macara 2016 — resolves RT_102)

Nelson mean daily global solar radiation: annual 15.2 MJ/m²/day, Jan 24.4, Jun 6.0 (Motueka 15.1, Takaka 15.2); ~2,400 sunshine hours (top-4 sunniest NZ). The ~25% June/January radiation ratio is the upstream physical basis for CR_010’s winter-solar swing and why off-grid winter coverage isn’t battery-economic at 41°S. OT_030
Winter solar suppression (primary behind CR_010’s fog caveat): inland Tasman winter anticyclones generate low cloud/fog “chiefly May–September”; Nelson Airport averages 17 fog days/yr, 60% (10 days) May–Aug. The “3–5 consecutive days” figure is a CR_010 characterisation, not a tabulated value in Macara 2016. OT_030
Heat load + wind: mean annual HDD (base 18°C) Nelson 2,108 (peaks Jul 346); cooling negligible (CDD 56) — corroborates the CR_015 pilot space-heat. Mean wind low inland — Motueka 5.0 km/hr, Nelson 11.7, exposed Farewell Spit 21.2; small wind viable only on exposed coast, corroborating CR_013’s low pilot CF. OT_030

Network Tasman DG connection — regulatory layer

For community-scale generation in the pilot footprint: prescribed application fees $550 (10-100 kW) /$ 1,100 (100 kW–1 MW) / $5,500 (≥1 MW) +GST; avoided-transmission credit viable only above ~20 kW sustained over winter-evening peak (needs half-hourly export metering); approval in 45/60/80 days by plant size; regulated terms lapse if not built within 18 months; mandatory AS/NZS 4777/3000/5033 compliance + COC + anti-islanding. The primary behind the DG-fee figures cited in CR_011. REG_002

Solar generation + off-grid economics (RA Machine Count 2025)

Solar-yield benchmark: 500 m² rooftop OR ground-mounted solar ≈ 130 MWh/yr for ~ $220,000 upfront, ~30-yr life (\approx260 kWh/m²/yr). The underlying **density and method are now sourced** ([[ot_154_rewiring-solar-area-calculator-2025|OT_154]]): effective **0.221 kWp/m²** (\approx4.5 m²/kWp) at CF 15% \to the ~$ 220,000 is a reconstruction from RA’s $2,000/kW scratch-sheet cost input (2,000 \times 0.221 \approx$ 442/m² × 500 m²; NOT the tool’s own broken $9,024/m² scratch output, and not the NI capex benchmark). OT_064
Solar area→kW→yield method + panel density (RA calculator — the method behind the 500 m² benchmark above). Rewiring’s own area-requirements calculator supplies the density OT_064 left implicit: an effective installed density ≈ 0.221 kWp/m² (0.4 kW panel / 1.627 m² module × 90% usable space; ≈ 4.5 m²/kWp), a 15% capacity factor on optimal roof/ground (“average across NZ regions”) reduced to a 14.475% effective roof CF for a double-gabled roof (opposite face yields 93% as much, from NIWA SolarView), and 0.5%/yr degradation (7.15% avg over 30 yr). These give ≈ 260 kWh/m²/yr rooftop / 270 kWh/m²/yr ground (degradation-adjusted) — reproducing the 500 m² × 260 = 130 MWh/yr benchmark — and a sizing rule: system kW = demand ÷ 8,760 ÷ CF; area = generation ÷ specific-yield (worked: 9,000 kWh/yr → 6.85 kW → 34.5 m² roof / 33.3 m² ground). The 15% CF agrees with pv_yield (~15%, RD_013) / EECA ~16% (URL_013); the density is a community rooftop/ground packing figure (contrast utility-scale ~35 Wp-ac/m², OT_056, which includes inter-row/tracker land). Method + density only — the tool’s cost inputs ( $1,000/kW default; the$ 2,000/kW scratch input whose reconstruction against the 0.221 density — ≈ $442/m² — reproduces OT_064's$ 220,000) are RA’s own and are NOT used for NI capex, which is sourced to OT_077 / CR_024. OT_154
Off-grid rule-of-thumb: high-usage off-grid dwellings → solar + battery is usually cheapest; low-usage → wood-fired heating or occasional bottled gas can be more practical. Rakiura/Stewart Island runs on diesel-generated electricity that is “extraordinarily expensive and emissions-intensive” — a real NZ off-grid-island datapoint for the D21 grid-vs-off-grid framing. OT_064
NZ full-electrification worked examples: solar-irrigation case — 30 kW pump + 55 kW array → 74 MWh/yr, self-consuming >half (“at 9:30am on a foggy morning, already producing 50%”); Forest Lodge Orchard fully-electric farm cut energy cost $66,000\to$ 5,300/yr on ~160 kWh solar + ~20 electrified machines. OT_064
The electrification-LOAD + emissions-factor data layer behind the census (RA Machine Count DATABASE, OT_153). The workbook supplies the intensity constants and per-machine load figures OT_064 summarised: emissions factors electricity 0.074, natural gas 0.2027, LPG 0.219, wood 0.016, petrol 0.258, diesel 0.253 kgCO₂e/kWh; fuel energy densities petrol 9.5, diesel 10.72, LPG 7.38 kWh/L; an electricity price stack residential $0.34254/kWh** vs wholesale-spot **$ 0.1195 vs export $0.0797 (the self-consumption-vs-export asymmetry OT_065/OT_068 make load-bearing); and a per-machine “Total extra electricity demand to electrify machines (kWh/yr)” column — the electrification-load layer RT_229 was raised to calibrate. ⚠ The 0.074 kgCO₂e/kWh grid factor is a low, marginal-renewables value (RA’s choice) — cross-check against a government consumption factor before any NI carbon cell adopts it. OT_153

All-electric household energy budget (RA Investing in Tomorrow 2024, Fig 1)

Average NZ household energy: ~85 kWh/day (fossil home) → ~25 kWh/day all-electric (~70% cut from electrification efficiency — EV + heat-pump; insulation+sealing alone only −2%). The empirical anchor for an all-electric demand-level profile (≈9,125 kWh/yr; cf. OT_029 ~27 kWh/day). NZ rooftop-solar uptake only ~2.7% of households vs Australia ~35%. OT_067

Delivered cost of energy, c/kWh (RA Electric Farms 2024, Fig 1)

The absolute anchor for D21 grid-vs-off-grid economics: grid 33.9c/kWh (Gen 14.6 / Dx 9.5 / Retail 5.8 / Tx 2.2 / Metering 1.6 / Other 0.1; variable 24.3 + fixed 9.7); rooftop solar 6.2c (11.5c financed @5%); battery cycle 22.6c (32.0c financed); diesel generator 75.7c. (RA analysis of MBIE Energy Prices 2023 + QSDEP; battery basis $1,000/kWh+BMS — reconcile vs CR_008.) OT_066
Farms as mid-scale power stations (100 kW–10 MW gen / 100 kWh–5 MWh storage): Forest Lodge 45 kW solar + 120 kWh battery = ~45% self-supply with +900% use and NO new network; can export >100 kW (= 25 homes’ peak). Aurora CPD trial pays $1.50/kWh peak export; distribution networks run at only 30–40% utilisation. OT_066

Distributed-solar value layer (RA Delivered Cost of Energy 2024)

Behind-the-meter solar avoids delivery-chain costs grid-scale plant does not: distribution losses 2–8% (~8% on the LV network) + retail hedging ~5% → up to ~13% value advantage per kWh over grid-based generation, plus network-deferral value (Orion $77/kVA/yr at coincident peak, captured by a peak-reliable battery). OT_065
Self-consumed vs exported asymmetry: a self-consumed kWh is worth the full delivered cost (~6–13% above wholesale); an exported kWh earns only ~wholesale (loss-adjusted) — the economic basis for battery self-consumption and the D21 grid-vs-off-grid breakeven. NZ residential bill split: Gen 32 / Dx 27 / Retail 13 / Tx 10.5 / GST 13 / Metering 3.5%. OT_065
EA PRIMARY bill-component split (end-June 2026) — supersedes the OT_065 Sep-2024 quote above. The Electricity Authority’s own decomposition of the average NZ household power bill: Generation 38.5% · Distribution 24.5% · GST 13% · Retail 11% · Transmission 8% · Your meter 4.5% · Levies 0.5% (refreshed annually end-June). This is the regulator primary behind the split OT_065 carries second-hand from a Sep-2024 snapshot; between Sep-2024 and Jun-2026 Generation rose 32→38.5%, Distribution fell 27→24.5% — a genuine annual-refresh shift, not a correction. Use these figures for the current split. URL_023
Avoidable-vs-fixed decomposition of the grid price. Only part of the bill is per-kWh-avoidable behind the meter: Generation (38.5%) + Retail (11%) ≈ 49.5% is the energy/supply slice a self-consuming community displaces, while Transmission (8%) + Distribution (24.5%) = 32.5% network is recovered largely through fixed daily/lines charges a still-connected community keeps paying (Meter 4.5% + Levies 0.5% fixed regardless of use) — so self-consumption is worth ~the energy+retail slice, not the whole retail tariff. Refines the ~40.6 c/kWh avoided-cost baseline (RD_018) and cross-checks to a ~37% network / ~63% non-network ex-GST split (exact match to RD_018’s 15.2 c lines / 25.4 c energy). URL_023
Export-side in absolute c/kWh (RA Symmetrical Export Tariffs 2024): peak import ~33c vs peak export only ~12c today (wholesale only; Vector network “injection” charge = $0.0000) — a symmetrical export tariff would lift export to ~26c. Confirms NI should value exports at the buy-back (~12c, cf. CR_011), not delivered cost → self-consumption ~3× export value. 120,000 home batteries (5% of NZ households) = Manapouri’s peak power for 1–2 hrs (community-storage aggregation). OT_068
Octopus Peaker (NZ’s highest peak buy-back): export paid 23 c/kWh at peak (wkday 7–11am & 5–9pm), 10 c off-peak, 5 c overnight — battery/V2G required. The defensible peak-export ceiling for fit_c_kwh; the import≫export asymmetry (23c export vs ~33–40c import) keeps self-consumption ~1.5–1.7× more valuable than peak export, and the high rate only helps peak-generating mixes (wind/hydro/battery) — solar exports midday at the 10 c off-peak rate. URL_014

Upper Clutha DER — NZ DSO-orchestrated consumer-battery flexibility (Aurora AMP 2024)

A live NZ DSO deploys consumer solar-batteries + hot-water load to defer subtransmission capex. Aurora’s 2024 Asset Management Plan documents its non-exclusive solarZero partnership dispatching consumer-owned solar-battery systems (plus Aurora’s hot-water channels) during constrained peaks on the voltage-limited Upper Clutha 66 kV circuit — a “Flexibility Services” non-network solution whose value is to “defer large subtransmission investments” at “lower lifecycle cost”. The constrained asset it relieves: 33/66 kV autotransformers rated 36/30 MVA (winter/summer), winter capability voltage-limited to 33 MVA under N-1. A South-Island DSO corroboration of the network-deferral value driver (cf. Orion $77/kVA above) and a concrete case that a peak-shaving battery earns network value only at coincident peak. OT_109
⚠ The AMP carries the case, not the price. It does not publish the CPD $/kWh reward rate or hours — the "$ 1.50/kWh peak export” cited above is Rewiring’s secondary figure (OT_066), NOT in this AMP (which contains “CPP”, a regulatory reset, not “CPD”). Aurora’s flexibility mechanism lives in its separate Pricing Methodology (OT_163), now retrieved: there is no per-kWh reward — Aurora makes no DG payments (para 185); the value is a 50% CPD-kW export credit (avoided demand charge). Use OT_109 for the mechanism/case, not for a peak-battery $/kWh input. OT_109

Network-deferral value = the $77/kVA LRAIC, primary-sourced (Orion Pricing Methodology 2024 — the primary behind OT_065; resolves RT_233)

**Orion’s Appendix G derives its coincident-peak long-run average incremental cost (LRAIC) as $77/kVA/year** ($ 69 upper-HV + $8 lower-LV, six-step derivation, p.69) — the gross annual network cost a reliably-at-peak battery could defer, and the source of record behind the "$ 77/kVA/yr” figure OT_065 carries second-hand. ⚠ But the $77 is the GROSS avoided cost, not what a battery is paid:** Orion's realised export credit is set at **"approximately a third" of the full LRAIC** (§7.1), and the scheduled credits are tiny — **0.28 c/kWh anytime, 0.95 c/kWh peak, 0 c/kWh for PV on non-half-hour metering** (30-750 kW control-period export = 6.76 c/kW/day). So an NI "value of peak battery to network" cell must choose between the **$ 77/kVA/yr gross deferral value and the ~⅓ realised credit — they differ ~3×, and the choice materially changes any peak-battery payback. OT_125
A DSO-authored grid-vs-off-grid crossover benchmark + a demand-diversity factor. Orion’s own standalone subsidy-free test (§6, pp.56–57) prices a PV+battery microgrid alternative to its network at $0.38-0.68/kWh** (delivery-comparable; ~12 c/kWh wholesale energy already deducted) — **$ 0.38 large-scale rural PV+battery, $0.48** shared subdivision/industrial-subdivision PV+battery, **$ 0.68 individual per-installation — a rare distributor estimate of the off-grid crossover cost that corroborates the ~$100k/km line-extension economics in CR_037. It also gives a clean ~3× demand-diversity factor: an average residential customer peak of 7.4 kW collapses to just 2.3 kW per household at suburb (network) scale (§6) — directly useful for sizing a shared community connection or battery vs summing individual peaks. ⚠ Orion is a dense, low-cost central-Canterbury DSO (delivery ≈ 27% of the bill), so these are a lower-cost anchor, not a remote-community proxy — bound the national range via RT_360 alongside Aurora OT_109. OT_125
**Aurora’s own Pricing Methodology — the primary CPD tariff, and it REFUTES the “ $1.50/kWh Aurora pays" figure.** Aurora Energy's regulated *Pricing Methodology* (1 April 2024, RY25) carries the **Control Period Demand (CPD)** tariff the [[ot_109_aurora-amp-2024-upper-clutha-der|OT_109]] AMP pointed to. ⚠⚠ It **contradicts** the secondary figure above: Aurora states **"does not make payments to any owner of distributed generation"** (para 185) — so the "$ 1.50/kWh peak export” attributed to Aurora (OT_066) is not an Aurora tariff. The real mechanism is a demand-charge reduction: the Upper Clutha/Wānaka CPD credit scheme (trial from 1 April 2024, ≥69 kVA half-hourly-metered) includes 50% of CPD-period export in the customer’s average CPD kW (para 95), lowering the CPD price (¢/kW/day) billed (e.g. Central Otago residential 77.29 ¢/kW/day). Control Periods: ~20–50 cold-winter days May–Sept, typically 2–3 h (up to 10 h), ripple-signalled — no “80 hrs/yr” figure exists. Aurora’s LRMC of peak capacity is ** $107/kW (Dunedin),$ 455/kW (Queenstown), $882/kW (Central Otago & Wānaka)** — a higher-cost South-Island anchor for RT_360 alongside Orion's$ 77/kVA/yr (⚠ units differ: $/kW AIC present value vs$ /kVA/yr annualised). OT_163 OT_109

Forest Lodge Orchard — full-electrification worked example (CR_034)

NZ’s first 100% electric orchard: on-site PV + battery (staged 23 kW → 45 kW/120 kWh → 160 kW/300 kWh, ~200 MWh/yr ≈ 2× use) with the 130 kVA grid KEPT for backup + export (not islanded) — a live data point for the grid-vs-off-grid (A2) call: at a short grid distance, grid-backup beats islanding. Core insight: the fuel→electric switch is the dominant saving; solar+battery is secondary (whole-farm opex $58k\to$ 23k→$5.9k). Acts as a DER (exported during the 9 Aug 2021 national grid emergency; wholesale/spot + Aurora flexibility → cut line charges). Operator Mike Casey founded Rewiring Aotearoa (OT_064/OT_066, the latter co-authored). NI’s best end-to-end validation case. See forest_lodge_orchard. CR_034

NZ rural off-road diesel baseline — the farm fossil-load electrification displaces (EECA 2021)

NZ agriculture burns 295 M L of off-road diesel/yr — the single largest off-road diesel sector — in tractors, irrigation pumps, utes and heavy machinery (sheep & beef 108, dairy 95, arable + ag contractors 74, horticulture 18 M L); national off-road totals are 1,065 M L diesel/yr (~29% of NZ diesel) and 445 M L petrol/yr (~14%). This is the demand-side anchor for the farm-electrification economics above (OT_066 / CR_034) — what a rural community displaces when it electrifies its machinery. ⚠ The “$700M/yr agriculture diesel spend (EECA)” OT_066 cites is a Rewiring derivation (295 M L × ~diesel price), not a figure in this EECA report — it carries volumes only, no dollars. OT_126
Off-grid diesel gensets are back-up-only (D20 signal). The report finds diesel electricity generators on remote NZ farms are used infrequently, for short durations, as back-up to unreliable mains and consume insignificant fuel volumes — so a “remote-community diesel genset” is a firming/back-up device, not a standing rural fuel load (consistent with the firming framing in CR_030). OT_126

interviewee account (int_008): the economics + the off-grid verdict

Cost stack (lived): grid all-in ~ $0.40/kWh** (gen$ 0.19 + transmission $0.03 + distribution$ 0.13 + retail/metering $0.05) vs **~$ 0.11/kWh mortgage-financed rooftop solar vs ~ $0.25** self+battery vs **$ 1.50–2.00 diesel. “Even if generators gave power away free, it wouldn’t reach homes cheaper than their own rooftop solar.” Interview VIII [INT_008]
Off-grid verdict: technically “100% achievable” (with V2G + a shared battery), but uneconomic for a grid-reachable site — it forfeits export revenue and needs ~$1M of batteries to cover frost; the crossover is economic (export + curtailment + frost), not a single distance. Confirms the model’s grid-backup default. Interview VIII [INT_008]
Batteries = resilience, not arbitrage (I06): on dollars they ~break even; bought to “run my farm when there’s a power cut.” And the dominant economic win is the diesel→electric switch, which the off-grid framing wrongly merges with grid-cost + self-generation — a direct challenge to a pure self-sufficiency objective. Interview VIII [INT_008]
Tech mix: no hydro (no stream); wind uneconomic at micro-scale (*“get it below $0.18/kWh or buy more batteries"*); biomass not considered. Battery field-day price now ~$ 350/kWh (he paid $600). Interview VIII [INT_008]

Farm-scale (productive-load) solar+BESS field economics (Farmgen operator submission — ⚠ advocacy source)

Farm-scale solar+BESS pays back ~2× faster than residential — 3.5–6 yr vs 10–15 yr (50–75% self-consumption without a battery; 80–100% with a moderate 100–215 kWh battery), on a natural rural DG config of a 50 kW inverter + 75–90 kWp solar + 100–215 kWh storage, financed at 4–6% sustainability-linked rates. The productive-load (farm) counterpart to the residential PV+battery economics (CR_008/CR_024) — the mechanistic basis for modelling a community with an agricultural/productive load with better solar economics than a residential-only one. ⚠ Advocacy source: Farmgen’s own operator field data (>100 farms/yr), submitted to lift an EA DG eligibility threshold — treat as operator claims needing independent corroboration (RT_366). REG_026
Dairy load shape (>100 farms): morning peak 20–50 kW (5–9 am) + evening peak 20–50 kW (3–8 pm), consistent year-round, aligns with national system peaks; irrigation lines-charges run 40–60% of the bill (long feeders, low density) — a cost-to-serve / remoteness-premium signal that supports NI’s remoteness-cost logic. ⚠ CONFLICT with Interview VIII [INT_008]: Farmgen calls irrigation shiftable and day-windowed (“has not observed a single site running 24/7 for an entire month”), whereas an interviewee’s frost/irrigation pump runs 24/7 — treat irrigation duty-cycle as a segment-dependent (dairy/pivot vs frost-protection) battery-sizing assumption, not a general rule. REG_026

PV diurnal generation shape (CR_035, NI engine cell — resolves RT_221)

The fraction of daily rooftop-PV output in the 3 model slices: solar_day 0.63 / evening_peak 0.12 / night_base 0.25 (annual, north-facing; PVGIS-ERA5 4-NZ-city mean), replacing the illustrative 0.94/0.06/0. Used as a national constant — the shape is NZ-stable, only the yield magnitude regionalises (already in p_regional_table). Two corrections: evening-peak PV is ~12% not ~6%, and the ~25% “night_base” is really daylight shoulders (07–09, 15–16), not nocturnal (overnight PV = 0). ⚠ Strongly seasonal — winter evening_peak ≈ 0.00 (sun down by the 5–9pm peak); use summer ≈ 0.59/0.14/0.27 & winter ≈ 0.84/0.00/0.16 for seasonal stress-tests. Shape only (ERA5 under-reads yield). CR_035

Residential demand diurnal shape (OT_076, NI engine cell — resolves RT_224)

The model’s demand split 0.25 / 0.20 / 0.55 (solar_day/evening/night) is now sourced to EECA’s 2025 ~49,385-ICP half-hourly dataset (Appendix Six), replacing the triangulated CR_019/CR_020 — and it independently converges with GREEN Grid (0.23/0.26/0.51). No value change (it matches). Gross (pre-solar, incl. heating), per-dwelling, night-heavy. The 3-slice fractions are derived from the cluster ratios (±0.02–0.03/slice; evening 0.20–0.26). Pairs with CR_035 (generation) for a fully-sourced temporal engine. ⚠ gross vs the model’s heating-stripped A_stripped are close but distinct constructs. OT_076

LFP battery RTE + degradation (CR_036, NI engine cell — resolves RT_222)

AC-AC round-trip efficiency ≈ 0.88 (Tesla Megapack 2 datasheet 89% AC incl. all conversion+thermal losses; NREL ATB 85%) → replaces the assumed batt_rte 0.90. Keep the DC-stack RTE (95–96%) OUT — the engine meters AC. Lifecycle: ~2%/yr fade, 95% usable DoD (Pylontech), ~15-yr life → a year-15 replacement-capex term (the model previously ignored degradation). Corroborated by int_008 (an interviewee: 15–20 yr, ~$0.18/kWh to cycle). CR_036
Primary-source efficiency boundary + a CR_036 correction (Tesla Powerwall 3 datasheet). The 89% RTE CR_008/CR_036 carried is verbatim “Solar to Battery to Home/Grid Efficiency: 89%” (25 °C, beginning of life, 3.3 kW, “typical solar shifting use case”) and “Solar to Home/Grid Efficiency: 97.5%” — a solar-charged full path (PV → battery → AC), NOT a grid-charged AC-AC battery round-trip → keep batt_rte at the battery-only 0.88 (NREL ATB leg), and use 89% only where the modelled path is solar-charged storage. ⚠ This 89% is exactly the figure CR_036 mis-attributed to the Tesla Megapack 2 — it is the Powerwall 3’s solar-charged efficiency, not a Megapack AC-AC round-trip (the real Megapack 2 is 92–94% AC-AC). DS_003
NZ-applicable unit ratings (grid-certified for Australia and New Zealand, 230 VAC / 50 Hz single phase): 13.5 kWh AC, up to 11.04 kW AC continuous, up to 4 units/install (≈ 54 kWh / ~44 kW AC), 20 kW DC solar across 3 MPPTs, 185 A LRA motor-start, IP55/IP67, –20 to 50 °C — an off-grid/resilience storage building block at equipment-rating level (installed cost stays with CR_008). DS_003

Community/distributed rooftop PV cost (OT_077 — resolves RT_217)

pv_roof_cost ≈ NZ $1,800/kWp installed** for a shared community array (marae/school/papakāinga aggregate onto shared roofs \to mid-scale 10-250 kWp band; EECA *Commercial-scale Solar*$ 1,500–2,000/kWp + installer market $1,400-1,800). Use **~$ 2,000/kWp for many individual home systems; full spread $1,400 (large commercial) \to$ 2,360 (small 3 kWp). Excl. batteries + grid. Fills the gap OT_056 (utility-scale) leaves. OT_077

Rural grid connection costs / the A2 breakeven (CR_037 — resolves RT_214 + RT_215)

grid_extension_cost_nzd_per_km 70k → ~ $100,000/km** (rural 3-phase overhead 11 kV, EA build rates + Level/BRANZ) and **`grid_connection_fixed_nzd` 20k \to ~$ 12,000 (Orion fixed contribution). Off-grid crossover ≈ 1.5 km of new line (Powerco “Base Power”) — beyond it, standalone solar+battery ( $40-100k) wins; matches int_008 (cable-vs-setup). ⚠$ /km swings 5×+ (SWER ~ $50k; underground/difficult$ 150–250k+) → keep user-adjustable. CR_037
**Sector cross-check on the $/km (OT_224, PwC 2024 information-disclosure compendium).** Regulatory asset base per circuit-km across all 29 NZ distributors runs ~$ 60,400/km (rural, Network Tasman) to ~ $130,600/km (denser networks), industry mean ~$ 107,700/km, which brackets the derived ~ $100,000/km line-extension estimate as an order-of-magnitude check. Caveat: RAB is depreciated all-asset value (lines, transformers, substations), not a marginal build cost, so it corroborates the figure rather than replacing it; annual capex (~$ 8,600/km/yr) is not a build cost. OT_224

Hot-water (DHW) cost (CR_038 — advances RT_003)

A discrete domestic-hot-water cost cell: **resistance cylinder ≈ $3,000** (180 L; ~$ 4,800 at 300 L) or a **heat-pump HW system ≈ $7,000** (190-300 L; range$ 6–9k, up to $13k relocated), **COP 3.2-4.0** (Reclaim CO₂ "~5" = vendor upper bound). Hot water \approx 30% of household energy; HW heat-pump running cost \approx 25-35% of resistance. Feeds a **separated space-vs-water heat slice** (the "heat gross\touseful" refinement). ⚠ community/shared-tank$ /L not publicly priced (RT_003 stays open); don’t default a Warmer Kiwi Homes subsidy (space-heat scheme). CR_038

NZ community-energy co-funding + DER/VPP policy signal (MBIE Budget 2023 CERF bid)

MBIE’s Budget 2023 CERF funding bid sought $50.152m operating over four years** to expand community renewable energy: a **$ 30m boost to the Community Renewable Energy Programme (grants/co-funding for small-scale community projects targeting low-income/energy-insecure communities) plus a $5m/yr ($ 20m) innovation stream for household- and community-scale distributed solar+battery with demand response acting as internet-coordinated “virtual power plants” for peak shaving and network resilience. A primary NZ policy signal that DER + demand response is a funded direction; per-site cost/config sit in URL_015, not here. ⚠ Funding-envelope figures only — no per-site CapEx/kW config. OT_120
EECA Community Renewable Energy Fund (CREF) Round 2 (announced July 2025) — the delivery-stage regional-partner co-funding allocation: EECA approved 22 regional partners (district/city councils, regional councils, and iwi trusts — Trust Tairāwhiti, Tatau Tatau o Te Wairoa) for $9.6M EECA co-funding +$ 3.2M partner commitment, spanning Northland to Westland — a nationally-distributed community solar+BESS co-funding channel. Per-partner EECA amounts range $132k (Kawerau DC) to$ 1.188M (Northland RC). No per-site kW/kWh config (funding-allocation document); completes the CREF-family provenance chain (OT_120 Budget-2023 bid → this Round 2 delivery). OT_150

Roof-pool floor area + storey mix (OT_123 — BRANZ SR501, verified primary behind CR_018; advances RT_206 → resolved / RT_304)

2023 new houses (single detached units): average floor area 181.4 m² survey-weighted / 187.8 m² Stats NZ consent (Table 10), and 14% multi-storey (2+ storeys) → ~86% single storey (§3 Flooring). This is the verified BRANZ primary behind the roof_per_dwelling_m2 (170) / roof_mount_per_dwelling_m2 floor-area basis — previously held only through the compiled CR_018 (“survey 181 m², consent 188 m²”), now confirmed exactly. The 14% multi-storey share is the floor-area→ground-footprint correction: single-storey roof footprint ≈ floor area, but the multi-storey stock’s roof footprint is smaller than its total floor area (drives the roof-PV mount pool D01). Roof cladding is predominantly sheet metal 71.6% (Table 1). ⚠ Houses-only (single detached) — excludes townhouses/apartments, so it reads ~181–188 m² and understates roof-pool shrinkage for medium-density built forms. OT_123

Off-grid RE system design & LCA — international (Aberilla et al. 2020)

Hybridising PV + wind cuts storage need ~70% and per-kWh impact up to 40% — the design lever behind a complementary mix (Aberilla et al. 2020, Philippines LCA). In a cradle-to-grave LCA of 21 off-grid configurations for a prototypical 50-household tropical-island community, household hybrid PV-wind-battery systems have 17–40% lower impacts per kWh than the equivalent stand-alone installations, chiefly because solar and wind peak at different times of day so the hybrid needs 70% less battery capacity (plus a ~half-size wind turbine). At community scale the hybrid PV-wind-lead-acid micro-grid (C-PV+WT+LA) has the lowest impacts in 10 of 18 categories and is the environmentally most sustainable single design; the overall optimum is household-scale PV + community-scale wind turbines + Li-ion batteries. Environmental corroboration of NI’s diurnal-complementarity / hybrid-mix logic (LIT_032, CR_020). ⚠ Philippines resource (solar 5.27 kWh/m²/day, wind 5.66 m/s @50 m) + Chinese-made components → transfer the relative design directions, not the absolute g CO₂/kWh (GWP 105–470). LIT_078
Batteries are the environmental hotspot, and a battery on a diesel genset is a cheap efficiency lever (Aberilla et al. 2020). Energy storage causes up to 88% of a home system’s mineral-resource depletion (78% for micro-grids) and a large share of most other categories — a right-sizing argument that reinforces the “design to an accepted unmet-energy fraction (LPSP ~1–5%), don’t over-size for 100% reliability” lever in CR_030. Conversely, adding a battery to a diesel backstop lets it run half the year on 30% less fuel (Li-ion cuts genset impacts ~30%, lead-acid ~20% per kWh), and integrating renewables cuts genset fuel 62–85% — supporting the “diesel genset + oversized battery + demand flexibility” NZ stack in CR_031. Li-ion beats lead-acid in most categories except eutrophication and human/terrestrial toxicity. LIT_078

NZ non-residential building electricity intensity — the UPPER anchor for the #12 community-building cells (OT_159 — BRANZ BEES SR297/1, verified primary; advances RT_328, kept open)

The only measured NZ non-residential electricity-intensity dataset — a commercial UPPER bound on the assumed community-building intensities. BEES (the non-residential twin of HEEP OT_037) measured ~41,000 NZ commercial office + retail buildings: national EnPIelec 173 ±28 kWh/m²·yr, rising with size (smallest stratum S1 ≤650 m² = 143 ±57 → S5 ≥9,000 m² = 223 ±66), and by use Commercial Office 186 / Commercial Retail 176 / “Other BEES” 158. These sit 3–30× ABOVE the engine params.py #12 assumed community values (barn 5, glasshouse 10, hall 30, workshop 40, school 50 kWh/m²·yr) — correctly, because BEES premises are fully-occupied, intensively-serviced shops and offices, whereas the model’s halls/workshops/barns/glasshouses are intermittently used and lightly serviced. So BEES bounds the #12 assumptions from above and confirms they sit well below any NZ commercial-building floor (a directional sanity check) but is NOT a per-type benchmark and does not move barn/glasshouse/hall/workshop/school off assumed. The BEES targeted-monitoring set does show individual low-load small premises can run far lower (a sheltered “Other” premise at 13 kWh/m²·yr, a Clothing Store at 48) — evidence the low community values are directionally plausible, not that they are validated. Office/Multiple-Use electricity splits by the “one-third rule” (≈⅓ lighting / ⅓ plug load / ⅓ space conditioning + other). ⚠ Scope: office/retail only; ⚠ vintage: fieldwork ~2007–2012 (LED only 2% of premises then). OT_159

Demand-side load benchmarks — dairy sheds & coolstores (electricity LOAD, not generation)

Dairy-shed electricity load (NZ): whole-shed electricity ~150–177 kWh/cow/yr (irrigation excluded), of which milk cooling ~22–33 kWh/cow/yr; a derived micro-dairy scenario runs ~131–399 kWh per 1,000 L at 1–5 cows. This is a productive-load demand input, not a generation source — it sizes the milking + milk-cooling load a self-sufficient dairying community must supply. CR_057 (primaries: LIT_117, OT_203, REG_033, OT_204).
Coolstore electricity load (NZ): chilled-fruit cold storage ~79 kWh/m³/yr mean (range 35–151; central planning figure ~80, sensitivity band 100–150), with kiwifruit at ~0.44 kWh/TE (tray equivalent). Post-harvest cold storage is a demand load the engine must cover, not a supply option. CR_058 (primaries: LIT_118, OT_205, LIT_119 — Evans = international proxy).

SSI connections

I07 Fulfilment of basic needs — on-site energy generation directly addresses energy as a basic need; ESR = E_local / E_demand is the primary metric. CR_002
I09 Environmental sustainability — renewable energy eliminates fossil fuel dependence; agro-PV preserves farmland; bird/bat detection resolves wildlife impact. Interview II [INT_002]
I01 Financial & economic sufficiency — local generation reduces household energy costs; 4–5 year storage payback validates the investment case; community MG LCOE comparable to grid. Interview II [INT_002] LIT_002
I06 Resistance to external shocks — on-site storage and grid backup insulate community from grid outages and price volatility; NZ HVDC vulnerability makes community MG resilience design critical. Interview I [INT_001] Interview II [INT_002] LIT_002
I02 Food security — agro-PV enables food and energy production on the same land, resolving the land-use trade-off. Interview II [INT_002]

Relevance to Neobiome

For a small community (10–100 units), the D01 design stack integrates both heat and electricity:

Heat: (1) Passive building design to minimise demand. (2) Biomass district heating for heat baseload using local forestry waste — central community-scale boiler, not individual units. (3) Supplementary thermal storage or heat pump for peak load. Interview I [INT_001]

Electricity: (1) Household PV panels (agro-PV where farmland is available). (2) Single centralized storage unit (1–2 MW, off-the-shelf) — avoids 2–3× cost premium and coordination burden of household batteries. (3) Central production unit (1–3 MW) for baseline stability. (4) Grid connection as backup — even a self-sufficient community needs the equivalent of “road infrastructure.” Interview II [INT_002]

Community microgrid architecture packages these components into a locally owned and operated system. The Totarabank eco-village case study (NZ) — with a design LCOE of $0.094/kWh (baseline) /$ 0.109/kWh (resilient) benchmarked by Mohseni et al. — is the closest published community-scale analogue to Neobiome’s design context. LIT_002 LIT_032

Cross-cutting principle: Technology complexity must not exceed the community’s internal maintenance capacity. Interview I [INT_001]

NZ community solar benchmark

Wellington latitude (~41.3°S) community design: 15kW PV sufficient for 16 inhabitants (all electrical needs + water heating confirmed via Cohaus field visit). Equivalent to ~937W/person installed capacity. Design-derived; not empirically measured. OT_018

NZ residential electricity demand baseline (Tasman/Lower Moutere pilot context)

NZ national average household electricity demand (MBIE March 2024): 7,088 kWh/yr; Tasman regional 7,295 kWh/yr (4th highest of 16 NZ regions). Recommended NI design baseline for the Tasman/Lower Moutere 50-household pilot: 8,000 kWh/year per household (matches MBIE QSDEP standard 4-person household, conservative all-electric with heat pump + electric HWC). Aggregate pilot demand: 400 MWh/year ≈ 1,096 kWh/day. Partially addresses RT_077 via synthesis; primary BRANZ HEEP / MBIE retrieval pending (RT_094, RT_095, RT_097). CR_009
At CR_009 conservative baseline and NZ 14% capacity factor (per OT_001), a 50-household pilot implies a community PV array of approximately 326 kW. Note: the OT_018 per-person extrapolation (937 W/person × 140 persons ≈ 131 kW) presumes a passive + heat-pump efficiency stack reducing per-household demand to ~5,500–6,500 kWh/yr — the wiki holds both anchors. CR_009
In all-electric homes, space + water heating together ≈ 50–65% of total electricity use (derived from BRANZ HEEP end-use shares: 34% space heating / 29% water heating / 37% appliances). Demand-side reduction levers (passive house envelope, heat pump space heating, heat pump hot water cylinder) target this dominant share before generation/storage is sized. CR_009
South Island regions (Southland 8,132, Canterbury 8,046, Otago 7,853 kWh/yr) run higher than NZ average due to colder winters, no reticulated natural gas, higher all-electric proportion. Tasman 7,295 sits between this band and the North Island mean — design baselines should not assume Auckland/Wellington-typical demand. CR_009
NZ residential demand is bi-modal (“camel’s back”) — a morning shoulder (07–09) and a dominant evening peak (17–21), sharper in winter. The three time-of-day slices of daily household electricity are ~0.22 / 0.38 / 0.40 (total) or ~0.27 / 0.34 / 0.39 heating-stripped (solar_day / evening_peak / night_base): the demand-shape input for the NI electricity engine’s 3-slice balance. Triangulated estimate, not a measured curve. CR_019
~38% of the winter evening peak is space + water heating (~21% space + ~17% hot water); because the model handles heating as a separate domain, the elec_nonheat shape is flatter than the total-load curve. CR_019
Primary measured demand data (GREEN Grid, Table 3.1): per-dwelling kW by period — winter 0.60/0.48/0.94/0.41 (morning/day/evening/night), summer 0.41/0.33/0.44/0.24. Derived 3-slice energy fractions ~0.23/0.27/0.50 (annual, total load) → confirms CR_020 (Research A) and refutes CR_019’s 0.38 evening (peak-power vs energy-share). n=44 non-random sample, per-dwelling total load. The held primary behind the demand-shape options. RD_019
A companion reconstruction (Research A) from the same GREEN Grid period-averages gives a lower evening fraction — total 0.23/0.26/0.51, heating-stripped 0.25/0.20/0.55; the two estimates diverge on the evening peak (0.26 vs 0.38), the load-bearing uncertainty for battery sizing (held as competing demand-shape options in the workbook pending RT_224/RT_225). CR_020
Modelling residential solar at coarser time resolution understates export: 30-min vs 1-min by ~1–2% of load, 60-min by ~2.0–2.6% — the NI 3-slice model is coarser still, so its export figure is a conservative lower bound (corroborates the E5 export caveat). NZ residential self-consumption 21–44% at 3 kWp / 12–30% at 6 kWp (GREEN Grid, 7 households). OT_061
Small-wind cost (NZ): turbine $3,000-8,000/kW; full installed 1-3 kW grid system **$ 7,000–22,000/kW** ( $7-22/Wp), off-grid battery-backed$ 14–38/Wp; capacity factor 10–30%. At ~ $12k/kW vs PV ~$ 2.5k/kWp, small wind rarely pencils out except at windy off-grid sites — a useful model signal. OT_062
Wind-resource data layer (to source wind_cf): NIWA national climate maps (mean wind speed, 500 m grid, 1981–2010, DataHub; >8 m/s = good resource) + the Global Wind Atlas (10 m wind speed + power density, 250 m GIS, free) are the primary layers to re-derive small-wind CF (via a turbine power curve), replacing CR_013’s AI-derived values. ⚠ NZ’s world-class ~40% utility wind CF must NOT be used for small wind (10–30%; building-mounted <8%). CR_029
Micro-hydro (NZ): installed cost ~$8,000–30,000/kW (1 kW system, terrain-dependent); capacity factor ~50% (sources the engine’s @hydro_cf placeholder); power P = Q·H·9.8·η (η 0.5–0.7), head ≥10 m recommended (5 m can work), ≤50% flow diverted. Usually the lowest-cost micro-generation where a year-round stream exists. OT_062

National small-hydro resource layer + GIS siting method (MBIE 2020)

NZ small-scale (>1 MW) run-of-river resource map: 84 GIS-identified new schemes = 236 MW / 1,346 GWh/yr (@ 65% CF); +14 from literature → ~98 sites, 343 MW, ~2,000 GWh/yr. Regionally: West Coast dominant (17 schemes/55.6 MW), hill-country North Island next; Auckland nil, Tasman-Nelson modest (3/9.5 MW). ~half on DOC land (consenting). Small-hydro = locally valuable, too small for national demand. OT_075
The resource layer = NIWA River Flows / Percentile Flows (flow) + LINZ 8 m DEM (head) — the concrete datasets for the parcel-GIS terrain-hydro layer (spec §11 I4). Sizing method: P = ρ·g·Q·h_net·η, η 75%, h_net = h_gross×0.9, flow×head > 150.66 → 1 MW; design flow 65th/80th-percentile minus residual (90%/80% MALF); conveyance ≤3–5 km. CF 65% for run-of-river >1 MW (vs model hydro_cf 0.5 — community micro likely between). OT_075

Nelson–Tasman solar resource (Lower Moutere pilot supply side)

Annual specific yield Lower Moutere: 1,350–1,380 kWh/kWp/yr at optimal tilt, north-facing (NIWA SolarView + PVGIS ERA5 + Brent 2020 JRSNZ converge within ±5%). Bankable P90 ~1,250–1,280 kWh/kWp/yr. Implied capacity factor ~15.4–15.8%, above the national 14% CF assumption used in OT_001 and inherited by earlier sizing notes. CR_010
Optimal tilt at −41.3°S: 35–36° for annual maximum, 40–45° for off-grid winter-biased designs (battery-backed community systems). True north (azimuth 0°); east/west costs 10–15% of output. CR_010
Seasonal swing is the dominant battery design driver: summer-to-winter ratio is 1.5× by NIWA sunshine-hours or 3.7–4.5× by PVGIS solar-angle modelling. June output is 22–27% of January peak by PVGIS basis. For off-grid sizing, use PVGIS-derived winter minimum (1.5–2.0 PSH/day in June), not NIWA sunshine-hours (2.7 PSH/day) — PVGIS is more conservative at 41°S because of low winter solar elevation. CR_010
Tasman pilot updated array sizing (combining CR_009 demand and CR_010 yield): at 400 MWh/yr aggregate demand and regional 15.4% CF, 100% annual energy match ≈ 296 kWp (down from CR_009’s 326 kW national-CF estimate). At CR_010’s recommended 80% annual coverage with grid/generator backup: 500–700 kWp ground-mount + 1,500–2,500 kWh usable battery (1.5–2.5 day buffer). The 10 ha site can theoretically support 6,000–8,000 kWp — substantial headroom for agrivoltaic integration. CR_010
Anticyclonic winter fog risk specific to Waimea/Moutere: NIWA Climate of Nelson and Tasman (Macara 2016, cited via CR_010) notes winter anticyclones can produce fog in inland Tasman valleys for 3–5 consecutive days, suppressing generation. Battery design must avoid deep discharge during multi-day overcast winter periods. RT_102 to retrieve Macara 2016 for the primary characterisation. CR_010
Full winter coverage is not battery-economic — for mid-winter (June–August), grid connection or backup generator/biomass is strongly recommended. Converges with Interview II [INT_002] grid-backup principle and OT_001 NZ community battery sizing. CR_010

NZ solar export economics & regulation (Lower Moutere financial layer)

Self-consumption is worth 2.1–4.5× the value of export in NZ. Nelson retail import 36–40 c/kWh vs flat-rate export 8–17 c/kWh (best: Meridian Solar Plan / Octopus Flexi 17 c; Mercury/Contact 8–11 c). Effective solar cost from an owned system ~11 c/kWh over 25-year life. CR_011
For community-scale (500–700 kWp), residential buy-back rates do not apply. The pilot falls under Network Tasman’s commercial Distributed Generation process: application fees $550 + GST (10-100 kW),$ 1,100 (100 kW – 1 MW), $5,500 (1 MW+); 45-day approval for <1 MW; AS/NZS 4777.1/2/3 and 5033:2014 compliance; commercial PPA / wholesale-linked rates typically 10–15 c/kWh. CR_011
1 July 2026 regulatory reform: all large retailers (>5% market share, ~83% of households) must offer time-varying buy-back. Peak rates expected 20–40 c/kWh in morning (7–10am) and evening (5–9pm) windows. Lines companies must pay network injection rebates for peak supply. Households without battery gain little — midday solar is off-peak; reform incentivises solar + battery specifically. CR_011 ⚠ Primary now held (REG_028, EA 2B/2C decision 16 Jul 2025): confirms the >5% market-share threshold, the mandate to offer time-varying injection plans, and availability by 1 Oct 2026 (material progress by 1 Jul 2026) — but it sets no c/kWh rate (the 20–40 c/kWh peak band above stays a CR_011 estimate, exogenous) and states no household-share figure, so treat CR_011’s “~83% of households” as an untraced gloss, not a sourced number.
10 kW default export limit for residential connections (EA, late May 2026). Nelson Electricity + Network Tasman already at the 10 kW limit. Irrelevant for the 500–700 kWp community pilot (commercial DG). CR_011
Octopus OctopusPeaker plan: 40 c/kWh winter peak / 23 c other times / 10 c off-peak / 5 c night — requires battery or >10 kW system. Properly-dispatched battery achieves time-weighted annual ~25–35 c/kWh. The financial case for battery storage as revenue source, not just self-consumption tool. CR_011
Avoided transmission credits available from Network Tasman for >20 kW consistent winter peak generation — case-by-case assessment; separate revenue line beyond export tariffs. Network Tasman may also impose export curtailment or network-upgrade costs at the generator’s expense — early engagement essential. CR_011

Fraunhofer ISE LCOE 2024 — international anchor for Lower Moutere pilot economics

PV utility-scale LCOE 2024 at GHI 1,450 kWh/m²/yr (S France — direct Lower Moutere analogue per CR_010): 3.5–5.4 €cent/kWh ≈ NZD 6.5–10 c/kWh under real WACC 5.4%, 30-yr life, 80% debt at 7%. Closest available international comparator at NZ irradiance. Actual NZ number sits above this once NZ debt rates (6–7% vs German 5%) and freight/installation premium are applied — likely NZD 8–14 c/kWh community-scale ground-mount at Lower Moutere, pending NZ recalibration (RT_110). OT_021
PV utility CAPEX bookends 2024: 700–900 EUR/kWp ≈ NZD 1,295–1,665/kWp (German market floor, ex-VAT). NZ installation likely 1.5–2× this. PV rooftop small 1,000–2,000 EUR/kWp; Agri-PV 900–1,700 EUR/kWp. Battery (utility 3:2 ratio) 400–600 EUR/kWh ≈ NZD 740–1,110/kWh — converges with CR_008’s NZD 300–550/kWh for commercial-scale BESS, confirming NZ commercial battery pricing already sits at or below European utility levels. OT_021
PV+battery LCOE penalty by sizing ratio (Germany 2024): PV utility 3:2 ratio 6.0–10.8 €cent/kWh; PV rooftop large 2:1 ratio 7.3–16.0; PV rooftop small 1:1 ratio 9.1–22.5. Larger battery-to-PV increases LCOE. The Lower Moutere pilot at ~500 kWp + 1,500 kWh sits between 3:2 utility and 2:1 large-rooftop bands → German-base LCOE ≈ 6.0–16.0 €cent/kWh; NZ-recalibrated band likely NZD 12–25 c/kWh — well below NZ retail import (36–40 c/kWh, CR_011), above commercial PPA range (10–15 c/kWh). OT_021
Battery 15-year life vs PV 30-year life — replacement at 30–50% of initial battery CAPEX assumed in OT_021 (residential 40–50%, large rooftop 35%, utility 30%). NZ recalibration of this assumption needed for NI 25–30-yr LCOE forecasts (RT_111). OT_021
LCOE sensitivity hierarchy for PV (Fig 8): irradiance ≈ investment cost > lifetime > WACC > O&M. ±20% irradiance shifts LCOE by ~±18%; ±20% investment by ~±16%; ±20% WACC by only ±5%. For NI: site selection (irradiance) and bulk procurement (investment) deliver larger LCOE leverage than finance optimisation. OT_021
LCOE methodology for NI energy skill: Appendix gives NPV-based LCOE = (I₀ + Σ Aₜ/(1+i)ᵗ) / Σ Mₜ,ₑₗ/(1+i)ᵗ, real WACC throughout, all cash flows real-EUR; heat credit method for CHP; learning curve C(xₜ)=C(x₀)·(xₜ/x₀)⁻ᵇ, LR = 1−2⁻ᵇ. Mixing nominal and real cash flows explicitly disallowed. Recommended methodological template for the NI energy calculation skill. OT_021
2045 PV utility LCOE forecast (Germany, LR 15%): 3.0–5.0 €cent/kWh; PV+battery utility 3.7–7.6; onshore wind 3.7–7.9. Battery storage projected 130–700 EUR/kWh by 2045 (vs 400–1,000 today) — supports NI long-horizon scenarios where battery replacement at year 15 is materially cheaper than installation. OT_021

Lazard LCOE+ v17.0 — US/global investment-bank cost benchmark (bookend for NI cost layer)

Lazard LCOE+ v17.0 (US, unsubsidised, 2024): utility-scale solar PV LCOE USD 29-92/MWh, onshore wind USD 27-73/MWh, geothermal USD 64-106/MWh; utility PV+storage (4-hr) USD 60-210/MWh, wind+storage (onshore, 4-hr) USD 45-133/MWh. Gas combined cycle USD 45-108/MWh for comparison. US bookend set for NI cost-layer validation — requires NZ recalibration. OT_033 (p9)
Generation CAPEX bookends (Lazard, US 2024): utility solar PV USD 850-1,400/kW, community & C&I PV USD 1,300-2,900/kW, rooftop residential PV USD 2,300-4,150/kW; onshore wind USD 1,300-1,900/kW; geothermal USD 4,860-6,280/kW. Independent cross-check against RD_003 IRENA Oceania anchor and CR_008 NZ installer quotes. OT_033 (p35-36)
Standalone battery storage CAPEX (Lazard LCOS v9.0, DC, US 2024): utility-scale 4-hour USD 160-282/kWh; C&I (1 MW/2 MWh) USD 318-430/kWh; residential (0.006 MW/0.025 MWh) USD 984-1,406/kWh — residential per-kWh ~3-6x utility scale, quantifying the household-scale penalty flagged qualitatively in int_002. LCOS ($/MWh): utility 4-hr USD 170-296; C&I 2-hr USD 373-518; residential 4-hr USD 882-1,101. OT_033 (p20, p44)
Hybrid PV+storage / wind+storage design assumptions: 4-hour duration, 350 90%-DoD cycles/year, roundtrip efficiency 91% (PV+storage) / 88% (wind+storage), storage capital cost excl. inverter USD 249-421/kWh — a structural duty-cycle template, though a NZ islanded community may cycle differently. OT_033 (p37, p42)
Historic learning: average utility-scale solar PV LCOE fell 83% and onshore wind 65% since Lazard v3.0 (2009 PV-utility avg USD 359/MWh), but in v17.0 the low end of renewable LCOE rose for the first time ever, driven by high interest rates — the decline has plateaued. OT_033 (p4, p16)
Caveat: Lazard LCOE explicitly excludes grid-integration, transmission, congestion, curtailment, intermittency and permitting costs (p8) — these dominate self-sufficient/off-grid community systems, so Lazard figures understate true community-system cost. Firming cost is region-specific via ELCC (solar 8% CAISO to 57% SPP); NZ has no equivalent ELCC publication. OT_033 (p8, p15)

IRENA global cost dataset 2024 — Oceania regional anchors for NZ recalibration

Oceania utility-scale solar PV 2024 (weighted-average): CAPEX USD 944/kW ≈ NZD 1,560/kW; LCOE USD 0.049/kWh ≈ NZD 8 c/kWh. Percentile range USD 598–1,385/kW CAPEX, USD 0.033–0.065/kWh LCOE. Direct international anchor at the closest available regional aggregate (no standalone NZ row in IRENA). NZ community-scale will sit 1.5–2× above this Australian-utility-dominated floor. Sharpens RT_110 NZ recalibration target. RD_003
Oceania onshore wind 2024 (weighted-average): CAPEX USD 1,363/kW ≈ NZD 2,250/kW; LCOE USD 0.041/kWh ≈ NZD 6.8 c/kWh. Below solar PV on LCOE at weighted-average — Tasman pilot hybrid PV+wind worth feasibility assessment if wind regime supports it (RT to be added in wind feasibility ingest). RD_003
Solar PV global weighted-average LCOE 2010 → 2024: USD 0.417 → 0.043/kWh — a 90% drop in 14 years, alongside 87% installed-cost decline (USD 5,283 → 691/kW). The canonical “PV won the cost battle” benchmark; Fig S.1 trajectory shows annual learning-curve smoothness with cost plateau emerging from 2023. RD_003
Battery storage utility-scale installed cost 2010 → 2024: USD 2,571 → 192/kWh — a ~92% drop, with global deployment scaling from 0.086 GWh additions in 2010 to 169 GWh in 2024. USD 192/kWh ≈ NZD 320/kWh global utility floor; cross-validates CR_008 NZ commercial range (NZD 300–550/kWh) and undercuts OT_021 German utility (~NZD 740–1,110/kWh). NZ market sits 60–170% above the global floor depending on scale. RD_003
Learning rate divergence — IRENA vs Fraunhofer: IRENA empirical World PV LR 33.8%, Oceania 35.3%, OECD 37.5% vs Fraunhofer’s forecast LR of 15% (OT_021). For NI long-horizon scenarios, report bracketed forecasts using both — conservative (Fraunhofer 15%) and historical-empirical (IRENA 34%) — to honestly bound forecast uncertainty. Same logic for onshore wind: IRENA World 25%, Oceania 32.4% vs Fraunhofer 5%. RD_003
Oceania large-hydro weighted-average capacity factor 2018–2024: 41% (down from 61% in 2010–2017 cohort). Declining CF reflects newer projects on lower-grade sites and climate-driven hydrological variability — material concern for NZ given hydro is 60.5% of the national generation mix (RD_001). Adds weight to the renewable-diversification argument at community scale. RD_003
Bioenergy LCOE has stayed roughly flat 2010–2024 (USD 0.086 → 0.087/kWh global weighted-average) while solar/wind have collapsed. The community-scale bioenergy case is no longer cost-led — must be argued on resilience, feedstock independence, heat co-product, or seasonal complementarity, not USD/kWh competitiveness. Reframes Interview I [INT_001]‘s biomass district heating case as resilience/heat-led rather than cheaper-than-PV. RD_003
IRENA narrative-report companion (2025) — hybrid-system + forward-CAPEX evidence the datafile omits. Australia’s eight operational solar+wind+battery hybrid projects (412.2 MW generation + 188.4 MWh storage) reported a weighted-average LCOE of USD 0.051/kWh; the 17 US PV+battery hybrids (4,486 MW + 7,677 MWh) USD 0.079/kWh — the Australian figure is the nearest Oceania renewable-plus-storage benchmark, a utility-scale hybrid floor (NZ community-scale sits well above it). Short-term (2025–2029) learning-curve CAPEX projections: solar PV → ~USD 388/kW, onshore wind → ~USD 861/kW, offshore wind → ~USD 2,316/kW (“indicative, rather than predictive”). Utility-scale BESS LCOE averaged USD 104/MWh in 2024 (~USD 90/MWh for 1–4-hr US/China projects) — a levelised-storage complement to RD_003’s USD 192/kWh CAPEX floor. OT_115
Financing-cost machinery for the LCOE cells — the piece RD_003 lacked. 2024 WACC ranged 3.8% (Europe) to 12% (Africa); Oceania ~3.9% for both solar PV and onshore wind (Fig 1.13, ⚠ bar-chart read, approximate). Where project-level data are unavailable IRENA applies a standardised real-WACC path — OECD & China 7.5% (2010) → 5% (2020); rest of world 10% → 7.5% — and a minimum-WACC floor = 80% × cost of debt + 20% × cost of equity (Box A.2). Lets the international LCOE anchors be re-derived at an NZ-appropriate discount rate rather than inherited at IRENA’s regional WACC — the dominant recalibration lever. Advances (does not close) the NZ-WACC side of RT_110. OT_115

Remote-community renewables — national synthesis (CR_012)

National-scope synthesis of remote-community renewable options (solar PV, wind, biomass, small-hydro, geothermal) concludes hybrid solar–wind–battery microgrids — with biomass for heat and backup — are optimal for most remote NZ settings CR_012 (§7, §10).
Chatham Islands Renewable Energy Project (Point Durham Wind Farm, 2024): three refurbished Vestas V27 turbines at 225 kW each plus a 576 kWh grid-balancing battery; island has run days at 100% wind, seven-day average 90% renewable, expected 62–68% renewable share overall CR_012 (§3).
Motairehe (Great Barrier Island) microgrid modelling: solar PV + battery cut supply shortfalls 97% (from >2,000 marae shortfall hours to 64 community hours/year); candidate sizing heuristic solar ≈ daily load / 4, battery ≈ daily base load × 3 CR_012 (§2). For a 30-household grid-connected community, solar + battery cut average daily grid consumption 59% and peak 33% CR_012 (§7).
EECA wind resource: 82 onshore sites, 11.4 GW potential, 39–44 TWh/year; wind ~6% of national electricity now, projected 20–34% by 2035 and the largest single source by 2050; solar PV growth 51% (2023→2024) and forecast 6% of supply by 2035 CR_012 (§2, §3).
Biomass is NZ’s leading renewable heat option for remote (especially forested) communities — ~7% of primary energy now, projected 12–14% by 2035; bioenergy was 16.2% of fuel-and-heat consumption in 2022, solid biomass 92% of supply CR_012 (§4).

IEA Clean Energy Technology Guide 2024 — per-technology readiness lookup

NI deploy-ready technologies (TRL 9 in 2024, IEA Clean Tech Guide): Onshore wind, Building integrated photovoltaic systems (BIPV), Floating solar PV (up from TRL 8 in 2022), Seabed fixed offshore wind, Lithium-ion storage battery, Redox flow storage battery (up from TRL 8 in 2020), Air-to-air / Air-to-water / Exhaust air / Shallow ground-source heat pumps, Building envelope air sealing, Anaerobic digester cooking, Ice thermal storage in buildings, Electrical storage for building systems integration, Virtual net metering community-scale solar. Specify in NI energy designs with high confidence. RD_004
NI deployment-risk technologies (TRL 7-8 in 2024, IEA): Floating offshore wind turbine (TRL 8), Anaerobic digestion biomethane production (TRL 7-8), Dynamic building envelope (TRL 8), Smart inverter (TRL 8 — still pre-commercial despite ubiquity in industry marketing), Combined latent+sensible thermal storage (TRL 8), Direct current buildings system (TRL 7 — closest IEA-tracked entry to a “microgrid”). These need a pilot-context caveat in NI design. RD_004
NI prototype technologies (TRL 4-6 in 2024): Dynamic insulation (TRL 4, no improvement 2020-2024), Active latent heat storage (TRL 4), Tidal stream ocean current (TRL 6 — relevant for coastal NZ communities), Direct lithium extraction from brine (TRL 6, up from 5 in 2020). NOT for community SS deployment without explicit research-pilot framing. RD_004
TRL methodology: 1-9 scale from US DoD/NASA adopted by IEA — TRL 1-3 research / lab proof of concept; TRL 4-6 prototype / lab-to-pilot; TRL 7-8 demonstration; TRL 9 full commercial; TRL 10-11 mature market. NI calculation rule: TRL ≥9 deploy with confidence; TRL 7-8 deployment risk material, document pilot context; TRL <7 do not specify without research framing. RD_004
Microgrid integration NOT tracked as a discrete technology in the IEA CETG (640 entries, only 1 microgrid match — “Direct current buildings system” TRL 7). The IEA tracks COMPONENTS (PV, batteries, inverters, EMS) but does NOT track their INTEGRATION into community-scale microgrids. NI calculation skill must construct its own microgrid integration framework — empirical confirmation of iea_edt_taxonomy_mapping §7 framing-bias finding. RD_004

MBIE Interactive LCOE Comparison Tool 2021 — NZ utility-scale generation landscape

2021 NZ wind LCOE median NZD 68/MWh ≈ 6.8 c/kWh (45 plants, range $54-91). Empirically converges with RD_003 IRENA Oceania 2024 wind weighted-average USD 0.041/kWh ≈ NZD 68/MWh — NZ wind cost has been stable at ~NZD 68/MWh from 2021 through 2024. MBIE 2021 numbers usable as current-state approximation for wind. RD_005
2021 NZ solar LCOE median NZD 122/MWh ≈ 12.2 c/kWh (12 plants, range $70-128). RD_003 IRENA Oceania 2024 solar weighted-average USD 0.049/kWh ≈ NZD 81/MWh — NZ solar dropped ~33% in 3 years. MBIE 2021 solar numbers stale; use IRENA Oceania 2024 or OT_021 GHI-1450 figures instead. RD_005
NZ hydroelectric LCOE 2021 (217-plant tool aggregation) — Hydro Peaking Daily (HydPD) $18-48/MWh (lowest LCOE NZ generation), Hydro South Canterbury (HydSC)$ 26-70/MWh, Hydro Peaking (HydPK) $56-65/MWh, Hydro Run-of-River (HydRR)$ 56-116/MWh median $81. Confirms hydro as NZ baseload cost anchor — but RD_003 Oceania large-hydro capacity factor declined from 61% (2010-2017) to 41% (2018-2024), suggesting newer-build hydro LCOE will rise. RD_005
MBIE 2021 core LCOE assumptions: post-tax real discount rate 4.5% (sits between Fraunhofer Germany 3.2-3.5% and high-irradiation/non-OECD proxy 5.1-5.4%); Gas $6.7/GJ; Coal$ 5.6/GJ; Lignite $3/GJ; Carbon$ 35/t; NZD/USD 0.68. Fuel/carbon assumptions superseded by 2022-2024 NZ gas crisis and ETS price movement — methodology citation only for new-build NZ generation costing. RD_005
NZ-specific methodology dimensions: HVDC Cook Strait charge allocation; GWAP/TWAP (Generation/Time Weighted Average Price) adjustment; Haywards reference-node pricing; NZ PPI time-series rebasing. None of these exist in OT_021 Fraunhofer or RD_003 IRENA. For NZ utility-scale generation analysis these are the canonical methodological touchpoints. RD_005
MBIE 2021 plant-pipeline view — 12 Fully Consented wind projects, 31 Generic-Wind new project options, 18 Generic-Geo, plus 5 Applied for Consent, 3 Generic-Lower-Probability-Geo, 2 Proposed-Other. Captures NZ utility-scale new-build pipeline c. 2021. Multiple consented projects have since commissioned (Waipipi 2021, Harapaki 2023, Kaiwera Stage 1 2023). RD_005

EV batteries as community-scale energy storage (V2G/V2H integration)

V2G battery flexibility tops domestic technology hierarchy (Fig 8.12 German case study): V2G ±8 kWh/day > BESS 7.5 kWh > V1G > heat pump. EVs effectively become flexible community-scale storage when V2G/V2H-capable. Boundary case: iea_edt_taxonomy_mapping §5 — V2G straddles A3111 (on-board EV battery) and F511 (stationary BESS). NI’s energy calculation skill should treat V2G-capable EVs as conditional F511 contributions, modulated by plug-in rate. OT_024
EV grid demand 2035: 1,500 TWh globally (+4% world demand), +>10% Europe, +<6% China. For NZ at 12% sales share scaling to ~50% by 2035 the household-load shift is substantial; community-scale V2H + smart charging is the design lever to absorb without grid upgrade. OT_024
The methodology/framework layer behind the OT_024 V2G-as-storage hierarchy (IEA 2022 manual). Treats managed EV charging as a graded flexibility/storage resource — passive → V1G → V2H/V2B → V2G — with a benefits/limitations value table (V2G EUR 2 304/EV/yr saving → EUR −955/EV/yr net cost, Denmark; 19–600 h backup from a V2H + rooftop PV, US) that supplies the structure of the value stack (arbitrage + reserves + frequency response + distribution services) and the sign (V2G goes net-negative once bidirectional-charger cost + degradation are counted). ⚠ Illustrative overseas figures in EUR/USD, not NZ cost-cell inputs — the NI storage takeaway is that a V2H-capable EV is conditional community-scale storage, sized by plug-in/availability, echoing the iea_edt_taxonomy_mapping §5 A3111↔F511 boundary already flagged for OT_024. OT_118

IEA World Energy Investment 2026 — macro money-flow lens

Global energy investment 2026 ≈ USD 3.4 trillion, of which USD 2.2 tn clean (renewables, nuclear, grids, storage, low-em fuels, efficiency, electrification) vs USD 1.2 tn oil/gas/coal — clean nearly 2× fossil. Electricity-related spending = ~60% of all global energy investment (USD 1.6 tn supply + ~USD 0.4 tn end-use electrification). Macro framing for the “Age of Electricity” thesis claim. OT_025
BESS investment 2026 set to surpass USD 100 bn (+35% YoY); 2025 was USD 80 bn. Utility-scale 65%, BTM 35%; LFP chemistry in >90% of global BESS capacity. China launched world’s first utility-scale vanadium redox flow battery early 2026 + first CAES facility H1 2026 — long-duration energy storage (LDES) commercialisation signals; cross-validates Interview II [INT_002] characterisation of flow batteries scaling toward 20-40 MWh. OT_025
BESS revenue stack (US/Australia/GB 2025): ~55% energy arbitrage, balance capacity + ancillary. Rising BESS deployment is compressing ancillary revenues — ERCOT BESS annual revenues fell 50% YoY in 2025 even as energy-arbitrage share rose to 65%. BESS-as-a-Service models for behind-the-meter customers (fixed service payment, no household upfront capex) directly applicable to NZ community deployment financing — pairs with CR_008’s no-NZ-rebate finding. OT_025
Cost decline 2015→2025 (point estimates): Solar PV –80%, BESS –75%, EV-ICE premium –80%, Wind ≈ –15%, Upstream O&G –25%; Gas CCGT the only +5% riser. 1 GW solar PV: USD 3 bn (2015) → USD 0.7 bn (2025) — 10× annual additions on ~2.4× annual spend. Macro-level cross-check of OT_021 and RD_003 cost trajectories — close agreement; supports NI cost-forward assumptions. OT_025
Electricity grid bottleneck globally — ~600 GW of late-stage renewable projects sat in grid-connection queues 2025; demand-side delays now visible for industrial loads + EV charging too. Transformer/copper/aluminium price inflation drives part of the USD 450 bn grid spend; +17% projected 2026. NZ analogue: Lower Moutere pilot must check connection-queue position before sizing utility-scale generation. RT to be assessed in Lines vs MEU connection-queue research. OT_025
ACCESS scenario (universal electricity access by 2035) requires USD 250 bn over the next decade — >55% to grid extension/expansion, balance to mini-grids + standalone systems. Equity investment rises 7× to ~USD 3 bn/yr. Mini-grids relatively more grant-funded; standalone systems ~40% equity (smaller ticket, higher retail-customer risk). Most NI-relevant single ACCESS reference for off-grid / mini-grid community electrification financing structure; informs the energy-skill financing-assumption layer. OT_025

EECA EEUD 2017-2023 — NZ residential energy end-use baseline

NZ residential energy 2023 = 83.6 PJ (15.4% of national 542.7 PJ). Fuel mix: Electricity 57.0% (47.7 PJ), Petrol 16.9% (household vehicles), Wood 8.9%, Natural Gas 8.6%, LPG 4.6%, Diesel 3.1%, Solar 0.4%. Authoritative NZ government decomposition — direct anchor for Lower Moutere residential demand mix. RD_007
Residential by EndUseGroup 2023: Heating/Cooling 64.5%, Mobile Motive Power 20.0%, Electronics & Lighting 14.8%. Heating + transport = 84.5% of residential energy footprint — defines the dominant decarbonisation surface. RD_007
Residential electricity end-use breakdown 2023 (47.7 PJ total): Water Heating 26.7%, Electronics 20.5%, Space Heating 20.3%, Refrigeration 11.8%, Cooking 9.3%, Lighting 5.5%, Space Cooling 2.4%, Dishwashers 1.5%, Clothes Washing 1.4%, Clothes Drying 0.7%. Water + space heating = 47% — the heat-pump conversion / shiftable-load envelope for community PV+BESS sizing. RD_007
Per-household 2023: ~6,790 kWh electricity/hh/yr (24.4 GJ); ~11,900 kWh total energy/hh/yr (42.8 GJ). Cross-validates CR_009 at finer granularity. For Lower Moutere 50-HH pilot: ~340 MWh/yr residential electricity baseline before any productive load. RD_007
NZ transport 99% fossil 2023 — Diesel 49.8%, Petrol 40.4%, Aviation 8.9%, Electricity 0.5%. EV electricity grew from ~0.1% (2017) to 0.5% (2023) of transport energy. Empirical magnitude of the transport decarbonisation challenge that the EV trajectory in RD_006 (NZ EV sales share 12% 2025) must scale up to address. RD_007
Agriculture sector × fuel 2023 (Tasman pilot context): Non-Dairy Diesel 7.8 PJ, Dairy Electricity 6.5 PJ, Dairy Diesel 3.1 PJ, Indoor Cropping Coal 1.6 PJ + Gas 1.0 PJ. Dairy electricity dominates rural electricity demand; indoor cropping coal+gas is a discrete decarbonisation target overlapping with regional process-heat data. RD_007
Caveat: do not cite Wood / Solar / Geothermal residential time series as trend evidence — values are flat across all 7 years (2017-2023), likely 2007 EEUD baseline GDP-scaled rather than measured. Solar in particular implausibly flat given visible NZ rooftop PV growth. Per EECA methodology note on GDP-scaling for subsectors. RD_007

EECA Consumer Energy Monitor Q3 FY25 — NZ household efficiency potential + behavioural ceiling

8-action household efficiency-savings table (EECA internal analysis) — annual savings per NZ household if action is taken: (1) Heat only used rooms 945 kWh / NZD 310; (2) Turn off unused appliances 608 kWh / NZD 200; (3) Off-peak shifting 0 kWh / NZD 150 (ToU pricing arbitrage); (4) Reduce draughts 283 kWh / NZD 90; (5) Install LED 276 kWh / NZD 90; (6) Close curtains at sunset 249 kWh / NZD 80; (7) Clean heat pump filter 145 kWh / NZD 50; (8) Cold water laundry 89 kWh / NZD 30. Bundle ≈ 2,595 kWh + ~NZD 1,000/yr per household if all adopted. Against RD_007 residential electricity baseline 6,790 kWh/hh/yr, the bundle is the theoretical ~38% demand-reduction ceiling. Caveat: EECA internal analysis, not externally peer-reviewed. OT_026
Behavioural ceiling vs technical ceiling: % NZ households always-doing low-cost actions = Cold water washes 46%, Heat only used rooms 40%, Close curtains 39%, Turn off appliances 37%, Clean HP filter only 18%, Use off-peak only 9%. Off-peak shifting is the largest awareness-to-action gap (55% aware, 9% always doing — 46-point delta). NI demand-side modelling should not assume off-peak shifting >9% baseline without community-coordination justification. OT_026
Off-peak pricing plan penetration: 32% of NZ households (n=2,308 FY25). Of those with plan: 42% use it a lot, 45% a little, 13% don’t use or unsure. Appliances shifted off-peak (among users): Clothes washer 66%, Dishwasher 58%, Clothes dryer 49%, Heat pump 40%, Hot water cylinder 26%, Other elec heating 17%, EV charger 12%. HWC + heat pump = the shiftable thermal load envelope for community-scale DR design — combined ~66% of off-peak users shift one of these. OT_026
Heat pump filter cleaning rate 18% always doing (54% aware) — implies ~80% of NZ households operate heat pumps with periodically-fouled filters. NI heat-pump efficiency assumptions should include a 5-10% filter-fouling derating for realistic delivered-energy modelling at community scale. OT_026

EECA Regional Heat Demand Database Aug 2024 — regional industrial process heat baseline

NZ national process heat (≥500 kW sites) 2024: 28.1 TWh / 101.3 PJ / ~6.0 GW capacity across 17 sector groupings; top 3 sectors = 73% (Wood Product Manufacturing 35%, Dairy 19%, Oil & Gas 19%). National fuel mix: Natural Gas 53% / By-products 30% / Coal 12% / Geothermal 1.7% / Biomass 1.5% / LPG + Diesel 1.6%. Fossil process heat to decarbonise = 18.8 TWh / 67.7 PJ at the ≥500 kW segment. RD_008
Nelson/Marlborough/Tasman regional process heat: ~163 GWh / ~75 MW across 10 sector cells (0.58% of national). Sectors (GWh / MW / sites): Dairy 51.8 / 7.0 / ≤2; Meat 31.7 / 15.0 / 4; F&B 26.4 / 16.1 / 8; Indoor Cropping 19.8 / 6.83 / ≤2; Healthcare 17.5 / 9.3 / ≤2; Education 5.1 / 8.9 / 9; Government 5.4 / 4.9 / ≤2; Other Manuf 3.0 / 3.2; Mining 2.3 / 5.0; Commercial 0.017 / 0.86. Privacy suppression blocks 7/10 NMT cells from precise site counts. RD_008
Indoor Cropping NMT = closest pilot-adjacent biomass district heating target — 19.8 GWh / 6.83 MW from ≤2 large glasshouse sites in the Tasman horticultural cluster (pip-fruit / kiwifruit / berries). 6.83 MW concentrated heat sits within the Interview I [INT_001] 1-5 MW mature mini-DH envelope (Austrian model, 35-year track record). Closest quantified regional analogue to int_001’s biomass district heating case in the wiki. RD_008
NMT biomass-conversion constraint = feedstock supply, not demand: NMT lacks the on-site Wood Product Manufacturing wood-byproducts feedstock that dominates Waikato/BoP fuel mix. Dairy/meat/F&B/horticulture industrial heat in NMT runs on LPG + coal + diesel (limited South Island reticulated gas). Local forestry/orchard residue capacity becomes the binding biomass parameter — consistent with Interview I [INT_001]‘s ~50 km feedstock-radius limit. RD_008
Cross-validation with RD_007: RD_007 industrial sector 2023 = 166.7 PJ total; fossil-fuel components = 92.5 PJ. RD_008 captures 67.7 PJ at ≥500 kW sites = ~73% of RD_007 industrial fossil — consistent at order-of-magnitude; residual ~25 PJ = sub-500 kW industrial + non-heat industrial fossil. Two independent NZ-government datasets converge on similar industrial fossil-heat magnitude. RD_008

EEUD methodology grounding — All EEUD-sourced figures in this domain (originating in RD_007) inherit the construction logic documented in OT_027. Modifier-vintage hierarchy: residential end-use cells use 2021 Residential Baseline Study proportions (defensible at fine granularity); seven commissioned-report sectors use 2019 DYE company-level audits (Dairy, Meat, Pulp/Paper, Wood Products, Petrochemicals, Primary Metals); all other sector × fuel cells use GDP-scaled 2007 EEUD proportions (16+ years stale) — explains the flat Wood/Solar/Geothermal residential trends. EEUD recognises heat-pump-for-heating across three end-uses (Low Temp Process Heat, Space Heating, Water Heating) — direct mapping for NI’s heat-pump-conversion logic. OT_027

RHDD methodology grounding — RD_008 is grounded in OT_028: data reference year = 2022 (Aug 2024 publication = SI-only Nov 2022 → whole-country July 2024 geographic extension, not data year revision). Reported GWh = fuel input, NOT delivered useful heat — apply boiler efficiency for thermal-load comparisons (60-85% industrial steam, >95% electric, ~300% COP industrial heat pump). 85% SI coal + 90%+ NI gas coverage at primary collection. ≤2-site privacy suppression triggers in low-density regions (explains 7/10 NMT cells suppressed). OT_028

NZ off-grid multi-carrier microgrid case (Rakiura/Stewart Island)

NZ off-grid island case (Rakiura/Stewart Island): MFOA-optimised 100% renewable multi-carrier microgrid sized at 796× 280 W PV panels, 31× 100 kW wind turbines, 18 kWh battery + 329 SC modules, 964 kW electrolyser, 619 kg H2 reservoir, and 261 kW fuel cell, serving electricity, heat, and hydrogen transport fuel for ~405 consumers. LIT_033
Blended LCOE of 0.27 NZD/kWh (0.24 NZD/kWh electricity, 0.0091 NZD/L hot water, 6.97 NZD/kg-H2 hydrogen) on a total NPC of NZD 7,940,348 over 20 years at 6% real discount rate (2019 NZD). LIT_033
Cost structure: non-dispatchable generation (WT + PV) ~52% of NPC (74% WT / 26% PV); hydrogen storage chain ~35%; balance of plant ~13%. Wind supplies ~79% and PV ~21% of annual generation. LIT_033
Three-timescale storage architecture — super-capacitors (transient), LiFePO4 batteries (daily/weekly), and hydrogen (seasonal) — achieves 0% loss-of-power-supply-probability across all three energy carriers in fully islanded operation. LIT_033

NZ off-grid island community case (Chatham Islands / Point Durham wind)

Off-grid remote-island community: 3× Vestas V27 (675 kW) + 576 kWh battery, diesel retained as backstop; targets 62–68% renewable (90% on good-wind weeks). Diesel cost ~ $1.8M \to ~$ 600k/yr; ~1,300 t CO₂/yr; ~600,000 kWh/yr surplus; $10M CERF-funded. A live D20 (renewables + backstop) + D21 (remote off-grid economics) exemplar; historic cost 129.5 c/kWh = extreme avoided-cost ceiling. ⚠ project-reported, medium quality. URL_012

Community-scale PV + net-export covenant case (Dancing Rabbit, USA — international comparator)

Dancing Rabbit (PRIMARY, Lockyer 2017): community electricity via the BEDR power cooperative operating 25 kW of solar PV, grid-connected under a covenant to export ≥2× the renewable energy drawn (3.5× in 2012); per-capita consumption 744 kWh/yr (18% of US average). A community-scale PV + net-export model serving ~65 people. ⚠ US case, not an NZ cell. LIT_081

Connections

Links to

Sources (194): CR_002 · CR_004 · CR_008 · CR_009 · CR_010 · CR_011 · CR_012 · CR_013 · CR_014 · CR_015 · CR_016 · CR_018 · +182 more

Technologies (7): Agro-PV (Dual-Use Solar + Agriculture) · Biogas (community-scale,… · Diesel Genset (community-scale backup) · Hydrogen Storage (community-scale, seasonal) · Micro-hydro (run-of-river, community-scale) · Solar-Direct PV Water Heating · community-scale)

Concepts (2): EDT Framework — Emerging & Disruptive Technolo… · IEA ↔ EDT Taxonomy Mapping

EDT domains (1): D02: Smart Food Systems & Agriculture

Cases (1): Electric Cherries

Referenced by

Sources (30): CR_047 · CR_051 · CR_054 · CR_058 · CR_059 · DS_004 · LIT_003 · LIT_004 · LIT_005 · LIT_006 · LIT_007 · LIT_076 · +18 more

Technologies (5): Community Microgrid · Diesel Genset (community-scale backup) · Hydrogen Storage (community-scale, seasonal) · Micro-hydro (run-of-river, community-scale) · community-scale)

Concepts (2): Low-Carbon & Bio-Based Construction · Regulatory Consenting for Off-Grid Communities…

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