NEOBIOME

I01: Financial & Economic Self-Sufficiency

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I01: Financial & Economic Self-Sufficiency

Indicators framework: LIT_001 · Calculation methodology: self_sufficiency_calculation · EDT convergence: edt_ssi_convergence

Definition

As named in the primary: Financial and economic self-sufficiency (Table 2). Bustamin et al. describe it as the ability of villages to manage financial resources effectively, reduce dependence on external assistance, and create economic opportunities for communities, with an appropriate debt-to-equity ratio, internal capital management, and diversification of products, markets and investments. LIT_001 (pp.5-6)

As rendered for this project: The ability of a village to manage financial resources effectively, reduce dependence on external assistance, and create economic opportunities for community members. (This wording is the project’s working definition, restated from CR_001, the synthesis of the primary. The primary’s own words are above.)

Relevance to Neobiome

[Why this indicator matters for eco-village design. What achieving it looks like in practice.]

Evidence

  • Voznyak et al. (2022) operationalise financial self-sufficiency through local budget self-sufficiency ratios, tax revenue independence scores, and per capita expenditure on housing and social services — now primary-sourced (the integral revenue+expenditure composite; see the method bullet below). LIT_075 CR_001

  • A worked composite-index method for the financial-sufficiency facet, now primary-sourced (Voznyak et al. 2022). Financial self-sufficiency is measured as an integral index decomposed into a revenue component and an expenditure component (7 per-capita/ratio sub-indicators each), normalised (stimulating vs destimulating), PCA-weighted (weights sum to 1 within each component), linear-weighted into component scores, then integrated. It is a template for how I01’s financial-autonomy sub-index can be composed from weighted sub-indicators — the same normalise→weight→integrate architecture the SSI uses. Sub-indicator menu for financial autonomy: own-revenue share, fiscal autonomy (tax/own-revenue), subsidiarity/transfer dependence, and the capital-vs-social expenditure mix (PCA weights, Lvivska oblast 2021: own-revenues-per-capita 18.5%, own-revenue-to-general-fund 19.0%, subsidiarity 16.1%; capital expenditure per capita 19.1% highest, social expenditure 3.3% least). Methodology, not an NZ figure — the results are Ukrainian municipal budgets, not household/eco-village finance. LIT_075

  • Empirical signal: most communities fail a financial-self-sufficiency test, and high self-sufficiency ≠ high development. Across all 73 territorial communities of Lvivska oblast (2021), 83.6% could not be regarded as financially self-sufficient; 75% of town communities scored low (integral 0.218–0.372), driven by weak fiscal capacity and high budget subsidiarity, and the taxonomic ranking found the moderate-efficiency group largest (45/73) — communities with high financial self-sufficiency “do not always show high socio-economic development paces.” A structural caution for I01: a strong financial-autonomy score is necessary but not sufficient for community economic development. Context caveat — fiscal/decentralisation scale, Ukraine. LIT_075

  • Jeerat et al. (2023): debt-to-equity ratios and internal capital management as primary financial resilience indicators in SEP agricultural communities. CR_001

  • LFP battery storage payback: 4–5 years at current prices; benchmark <1.5 cycles/day usage → 15+ year lifespan; total cost of ownership strongly favourable over asset life. Interview II [INT_002]

  • Renewables beat fossils on merit order — community energy investment in PV+storage is economically justified, not ideologically driven: “I don’t invest in PV because I’m green, I invest because that’s where the money is.” Interview II [INT_002]

  • Centralized community storage (1–2 MW) achieves 2–3× lower unit cost than household-scale batteries, reducing the capital burden of community energy independence. Interview II [INT_002]

  • Hardware cost for community-scale digital sensing and communications infrastructure (~20 households): “tens to hundreds of dollars” per node, not thousands; approximately 1/10 the cost of equivalent council-grade alternatives. Interview III [INT_003]

  • Community data marketplace (trajectory): communities share sensor data via a marketplace; AI-generated insights are sold to buyers (insurers, researchers, planners); revenue returns to communities — intended to create a self-funding economic loop for hardware replacement and local employment. Not yet operational as of May 2026. Interview III [INT_003]

  • Community MG solutions demonstrate comparable LCOEs to grid-sourced electricity in NZ eco-village and community contexts (Totarabank, Ohakune, Stewart Island, Great Barrier Island, 16-region study) — the investment case is economically justified on cost grounds alone. LIT_002

  • Community MGs can stabilise energy costs by shielding communities from wholesale electricity market price fluctuations — reducing financial exposure to external energy price shocks. LIT_002

  • Localised generation minimises transmission losses from long-distance energy transport, improving delivery efficiency and reducing operating costs for community energy systems. LIT_002

  • Totarabank optimised community-MG LCOE = 0.094/kWh baseline / 0.109/kWh resilient, vs Wairarapa retail $0.34/kWh (2020) — community-owned renewable generation is well below retail, not merely competitive. Investment case quantified: ROI 47.63%, IRR 54.51%, discounted payback 4.74 years vs the existing PV/grid base case — financeable by the local community without subsidy. (The NZD 0.19–0.27/kWh figure is the high-resilience sensitivity tail, not the design point.) LIT_032

  • Totarabank MG (Mohseni et al. 2021, LF-MFOA re-sizing): community-ownership investment case — MIRR 5.4%, DPI 1.43, LCOE −0.02/kWh (projected lifetime revenues exceed costs) vs the existing PV-only baseline at MIRR 2.2% / DPI 1.09; grid trading net-profitable ~2,517/yr; the 123,012 outlay recouped in ~10 years; framed as a low-risk, high-return opportunity ownable outright or via PPA/lease. Site retail tariff 0.23/kWh, feed-in tariff 0.08/kWh (2019 NZ). LIT_083

  • Community biogas plant capital cost: USD 1–3 million per medium-sized plant (World Bank, 2018) — key investment threshold for organic waste-based community energy; requires sustainable financing strategies (government subsidies, tax incentives, or innovative financing models). LIT_005

  • Grid electricity cost for a 336-house Indian village: 116,934/year; hybrid renewable generation cost: 70,877–75,316/year — annual savings of 41,618–$46,057. India-context figures; treat as structural benchmark rather than absolute NZ targets. LIT_003

  • Surplus generation sold at utility tariff yields 7,247–7,647/year additional revenue — community energy systems can generate income, not just savings. LIT_003

  • O&M costs for hybrid renewable systems: 9,023–9,040/year for a 336-house village — comparable to or below equivalent diesel-dependent maintenance costs. LIT_003

  • Community battery trials have uniformly required government funding: Alkimos Beach WA (ARENA 3.3M, 119 households, 81,376 total savings = 683.83/participant, 85% reduction in local energy consumption during peak periods — but 11/month fee subsidised); Western Power Powerbank WA (44 residents, avg 7.38 kWh stored/day, 5.23 kWh consumed from battery/day, 95% saved money, AUD$228/household total savings) — battery economics are pre-commercial at current hardware costs. OT_001

  • Fitzroy North VIC cost structure: battery hardware ~1,100/kWh (284kWh, 2022); total project cost ~1.5M (software development >50% of funded work + connection + artwork); OPEX ~$17,000/year (fixed: admin, IT, metering, maintenance, insurance) — fixed OPEX alone renders a single-system project commercially non-viable without subsidy; a larger battery programme amortises fixed costs over a larger revenue base. OT_001

  • Three community battery ownership models with distinct financial implications: EDB ownership (most prevalent, excluded from wholesale energy and ancillary markets in NZ); Retailer ownership (smoothest market access, mitigable by social enterprise model — e.g., Indigo Power returns 50% profits to Yackandandah community); Community/third-party ownership (access to full revenue stack, but requires grants or low-interest finance to overcome capital barrier). OT_001

  • “Double-charging” problem: standard NZ and AU network tariffs charge community batteries for both importing and exporting energy — ANU modelling confirms batteries only financially feasible if network tariffs are discounted; Local Use of System (LUOS) tariff required; no developed NZ market for network flexibility services. Wellington Electricity estimated $2–300M potential benefit from increased distribution network flexibility in Wellington alone. OT_001

  • Community shared thermal storage payback: 1.4–1.8 years vs. 2.5–3.6 years for equivalent distributed individual storage — infrastructure pooling shortens payback by up to 2.2 years across 20–30% discount rates; 5-year accumulated cost saving €3,000 (€375/household) for an 8-house community. Austin, TX data; treat as structural benchmark. Absolute investment cost not stated — see Open questions in lit_006_doroudchi-2022-thermal. LIT_006

  • Export price asymmetry: grid selling price for exported PV electricity ≈ 1/3 of purchasing price — quantifies why self-consumption through shared storage is financially dominant over export; applies broadly to grid-connected community energy systems where buyback rates are below retail import tariffs. LIT_006

  • NZ housing affordability threshold: <30% of disposable income on housing costs (Stats NZ/MSD standard measure); income-related rent (IRR) set at 25% of tenant’s income by MSD — the two benchmarks that define affordable housing in the NZ CHP sector and the most directly applicable NZ housing cost targets for community design. OT_003

  • Retrofitting insulation into existing NZ housing returns a benefit-to-cost ratio of 4.7:1 (whole-population Warmer Kiwi Homes evaluation; Grimes & Preval 2020), up from ~2:1 in the original randomised trial — a reusable NZ benchmark for the economics of high-performance habitat. (Headline figure summarised from the upstream Motu evaluation — cite that primary at calc time.) LIT_044

  • Direct public-sector cost of unsafe/substandard NZ housing is ~NZ141m/year, and the ~229 associated deaths monetise to ~NZ1 billion/year — the avoided-cost case for housing-quality investment, describing conventional NZ stock. Now primary-sourced: Riggs et al. (2021) attribute 36,649 hospital nights/yr to damp/mould (the dominant condition), 1,834 to cold homes and 806 to crowding, plus 115,555 home fall-injury claims; modelled via population attributable fractions. LIT_045 LIT_044

  • Housing-intervention programme ROI — primary behind LIT_044’s HHI figures (Pierse, White & Riggs 2019, He Kāinga Oranga/Motu for the Ministry of Health). The Healthy Homes Initiative cost ~19.2m** through Dec 2018 (**1,205/family staffing/delivery, excluding donor-funded intervention hardware) and is estimated to avert ~29.5m** in public health-care costs over 3 years (**10.4m in Year 1; Years 2–3 discounted at Treasury’s 6%), so ROI is realised in Year 2 (recouped in under two years). Per-event avoided-cost unit values: hospitalisation 4,090**, reduced-severity hospitalisation **541, GP visit 80** (Treasury CBAx), pharmaceutical dispensing **8.45. A NZ avoided-public-cost benchmark for the health economics of housing-quality investment — cite this primary, not the LIT_044 review, at calc time. ⚠ Excludes intervention hardware (often donor-funded) and all non-health benefits (school/work absenteeism), so it under-states both cost and benefit. OT_152

  • NZ housing crisis scale: 21,294 households on Housing Register (October 2024); $14b estimated social housing deficit; 219 median days to be housed — the demand context within which any community housing model must be situated. OT_003

  • Bond aggregator model: Community Housing Funding Agency (CHFA, 2024) raises bonds at scale and lower cost for NZ CHPs; Australia precedent (NHFIC): 4.1b loans approved, 740m interest savings — reducing cost of capital is the primary lever for scaling affordable community housing. OT_003

  • CHFA Commercial Paper Programme: NZ$2 billion programme limit; wholesale STNs (1–364 day tenor); A-1 (stable) S&P rating — quantifies the institutional funding capacity of NZ’s specialist community housing lender. OT_004

  • Crown formally announced support for CHFA in March 2025, including up to $150 million Crown loan facility; CHFA deliberately maintains lower net interest margin than banks, reducing overall government subsidy required per affordable home delivered. OT_004

  • NZ affordable housing threshold (market definition): <30% of gross (pre-tax) household income (CHFA Social Finance Framework) — contrast with Stats NZ/MSD measure (<30% of disposable income, cited in OT_003); gross-income threshold is slightly more permissive; both benchmarks are in active use in NZ housing policy and finance. OT_005

  • Mixed tenure cross-subsidy model: CHFA explicitly finances integrated developments combining social housing, assisted rentals, assisted ownership, and market-rate homes in a single project; the market-rate component improves CHP balance sheet capacity to deliver more affordable supply. OT_005

  • CHP sector scale (June 2025): fewer than 100 registered CHPs managing over 19,000 properties across NZ — quantifies the sector CHFA’s bond aggregator programme serves. OT_005

  • Waimārama Ōhanga Rau (Ngāti Kuri): community model linking housing development with employment creation across multiple sectors — housing as an economic development vehicle, not a net cost; integrates land, housing, and economic activity for community financial self-sufficiency. ot_006_er118-maori-housing-roadmap

  • Eco-community sharing economies reduce household production costs: shared materials, food co-ops, tool libraries, and communal maintenance mean residents need to work less for money — community-scale non-market exchange reduces the income threshold for economic sufficiency. LIT_014

  • He Puna Mārama cross-subsidy (Whangārei): CHP absorbs land and consenting costs to deliver homes at below-market value while operating a rangatahi-led construction company — community cross-subsidy architecture that converts upfront investment into long-term affordability and workforce capability. ot_006_er118-maori-housing-roadmap

  • 40% of NZ adults concerned about paying rent/mortgage now; 47% concerned in 12 months (renters: 55%) — NZ attitudinal baseline for housing financial pressure on household budgets (Ipsos Global Advisor, Jan 2025, n=1,001). OT_008

  • 83% of NZ renters want to own their home; 63% don’t believe they’ll ever be able to afford to buy — quantifies the affordability aspiration gap driving demand for alternative community housing models in NZ. OT_008

  • Riverside Community, Lower Moutere: full income pooling for ~70 years — all earned income pooled, members receive a modest allowance; the only NZ IC with this model still operating at time of study; demonstrates long-run economic viability of complete communal economy at community scale, but creates risk of “culture of dependency” dampening individual incentive and innovation. LIT_015

  • Enterprise conversion cost approximately $50–60k/hectare (Riverside context) — prohibitive barrier to shifting from one agricultural income model to another; locks communities into legacy enterprises even when these become unviable (cf. Riverside apple orchard → dairy). LIT_015

  • 100%+ electricity SS from roof PV and 100%+ freshwater SS from rainwater harvesting structurally eliminate grid electricity and municipal water utility costs at neighbourhood scale — multi-domain local provisioning translates directly to multi-domain cost elimination without specifying the quantum, which depends on local tariffs. LIT_022

  • Total global debt: $251 trillion (235% of GDP, 2024), rising across both advanced and developing economies; IMF projects 3.1% global GDP growth in 2026, below the 2000–2019 average of 3.7%. Economic downturn (#11 short-term, up 8 positions) and Inflation (#21, up 8) show the sharpest ranking increase of any risk category in the 2026 WEF survey — macro-economic fragility is the global backdrop within which community-scale financial self-sufficiency operates as a structural hedge. OT_014

  • NZ community battery CAPEX envelope (50-household pilot context): NZD 90,000–150,000 installed for 100 kWh stacked residential (Sungrow SBR ×4 or BYD HVM parallels); alternative containerised commercial system NZD 50,000–100,000 if procurable. EECA CREF average NZD $88,000 per site at 25% co-funding for eligible community resilience sites. Closes RT_034. CR_008

  • Community-scale BESS installation uplift of 30–60% over hardware cost dominates per-kWh delivered cost (enclosure 5–20k, BMS/EMS 3–10k, grid interconnection + protection relay 5–15k, commissioning 5–15k) — financial sizing must work from installed cost, not catalogue hardware prices. CR_008

  • No NZ residential battery rebate as of May 2026 — unlike Australia’s federal Cheaper Home Batteries Program, NZ has no equivalent subsidy. Removes one external-finance lever; community battery economics in NZ depend on EECA CREF co-funding, scale procurement, and low-cost capital. CR_008

  • NZ self-consumption-to-export value ratio: 2.1–4.5× (Nelson retail 36–40 c/kWh vs flat-rate export 8–17 c/kWh). LIT_006’s 1/3 Austin TX assumption (export ≈ retail/3) approximately holds at the upper bound (17/40 ≈ 0.43) but is worse at the lower bound (8/40 = 0.20). Partially addresses RT_004 (stays Open pending primary retailer sheets — RT_104, RT_107). CR_011

  • Battery arbitrage opportunity at community scale (post-1 July 2026): midday off-peak (10–17 c) → evening peak (36–40 c saved or 20–40 c earned via mandated ToU) = 20–30 c/kWh spread per cycle. For a 500 kWh community battery cycling once/day: ~36,500–54,750/year value above no-battery, before capital. Simple payback on arbitrage alone against CR_008’s NZD 90–150k community-scale battery CAPEX envelope: ~2–4 years. CR_011

  • Effective solar cost from owned system: ~11 c/kWh over 25-year life — substantially below NZ retail (36–40 c/kWh). Self-generation financial case is robust independent of export economics. CR_011

  • Network Tasman commercial DG application fees for the Lower Moutere pilot: 550 + GST** (10–100 kW), **1,100 (100 kW – 1 MW), $5,500 (1 MW+); 45-day approval for <1 MW. Modest at project budget scale. Avoided transmission cost credits available for >20 kW consistent winter peak — case-by-case. CR_011

  • PV utility-scale LCOE 2024 at Lower Moutere–equivalent GHI (1,450 kWh/m²/yr): 3.5–5.4 €cent/kWh ≈ NZD 6.5–10 c/kWh (Fraunhofer ISE international benchmark, WACC 5.4% real, 30-yr life). NZ-recalibrated likely NZD 8–14 c/kWh — competitive with NZ wholesale (10–15 c/kWh, CR_011) and far below NZ retail (36–40 c/kWh). Financial case for community-owned PV in Tasman is robust at international cost frontier; NZ-specific WACC recalibration pending (RT_110). OT_021

  • WACC is the dominant non-physical LCOE lever — Fraunhofer assumes 80% debt / 20% equity, debt 5% PV vs 7% conventional, real WACC 3.2–3.5% PV (Germany) vs 5.1–5.4% in higher-cost regions (Section 6). For NZ community-scale projects to land at the lower bound of LCOE, debt structure and cost must be optimised: NZ analogue would be CHFA-style aggregated debt at sub-market rates rather than retail commercial finance. Validates the OT_004 / OT_005 case for community-energy aggregated finance. OT_021

  • LCOE sensitivity hierarchy (Fraunhofer ISE 2024): ±20% irradiance → ±18% LCOE; ±20% CAPEX → ±16%; ±20% WACC → only ±5%; ±20% O&M → ±2%; lifetime extension reduces LCOE substantially. Site selection and bulk procurement deliver larger LCOE leverage than financing optimisation at the margins — sequence the NI design choices accordingly. OT_021

Lazard LCOE+ v17.0 — reusable capital-structure methodology + competitiveness frame

  • Lazard LCOE+ v17.0 supplies a reusable, fully-worked WACC/capital-structure methodology for community-energy investment cases: generation base case 60% debt at 8% + 40% equity at 12% = 7.7% after-tax WACC (20-year IRR basis); storage uses 20% debt / 80% equity. NI’s Lower Moutere worked example can transplant this structure and substitute NZ debt rates (~6-7%). OT_033 (p9, p13, p34, p43)

  • Cost-of-capital is the dominant LCOE driver: average utility solar PV LCOE swings from USD 40/MWh (4.2% WACC) to USD 59/MWh (10% WACC), onshore wind USD 46 to USD 74/MWh — quantifying why NZ-specific WACC recalibration (RT_110) is essential before any Lazard figure is used in an NZ community business case. OT_033 (p13)

  • Renewable competitiveness benchmark (US, unsubsidised): utility solar PV USD 29-92/MWh overlaps and undercuts gas combined cycle USD 45-108/MWh, supporting the merit-order economic case for community PV+storage investment that lit_002 and lit_032 confirm in NZ terms. Caveat: US dollars, subsidies and grid-integration costs excluded. OT_033 (p9)

  • IRENA Oceania utility-scale solar PV LCOE 2024: USD 0.049/kWh ≈ NZD 8 c/kWh (weighted-average; percentile band USD 0.033–0.065). Direct regional cost anchor for NZ utility-scale ground-mount; NZ community-scale will sit 1.5–2× above this floor. Sharpens OT_021’s NZD 8–14 c/kWh estimate to a defensible NZD 8 c/kWh anchor at utility scale. Partially addresses RT_110. RD_003

  • Global PV LCOE collapsed 90% in 14 years (USD 0.417 → 0.043/kWh, 2010 → 2024 weighted-average) — the canonical cost-learning benchmark for renewable energy. For NI long-horizon scenarios (2030, 2045), IRENA’s empirical learning rate (World PV 33.8%, Oceania 35.3%) is roughly 2× Fraunhofer’s forecast LR of 15% (OT_021). Recommend bracketed scenarios using both LR values to honestly bound forecast uncertainty. RD_003

  • IRENA financing-structure assumptions (2025 narrative report). 2024 WACC ranged 3.8% (Europe) to 12% (Africa); Oceania ~3.9% (Fig 1.13, ⚠ chart-read). Its standardised real-WACC path (OECD & China 7.5%→5% over 2010–2020; rest of world 10%→7.5%) and minimum-WACC-floor formula (80% × cost of debt + 20% × cost of equity, Box A.2) give a defensible cost-of-capital basis for a community-energy investment case — because renewable LCOE is dominated by financing cost, this is the single largest recalibration lever. Sits alongside the Lazard 7.7% after-tax WACC template (OT_033) and advances RT_110 (NZ-specific WACC still to be measured). OT_115

  • Avoided-cost evidence for the self-sufficiency investment case. Renewables avoided an estimated USD 467 billion in global fossil-fuel costs in 2024 (Australia USD 5.0 bn; Table S2), and Australia’s eight solar+wind+battery hybrids delivered a weighted-average USD 0.051/kWh — the nearest Oceania renewable-plus-storage cost benchmark, reinforcing that community-owned renewable+storage generation is cost-competitive at the utility floor (NZ community-scale sits above it). A distinct IRENA figure complementing the IEA WEI avoided-import macro bullet already on this page (OT_025). OT_115

  • NZ utility-scale LCOE landscape 2021 (MBIE) — for sector context — 217 plants, 22 technology codes. Wind median NZD 68/MWh; Hydro 18-116/MWh depending on category; CCGT 82-94/MWh; Solar median NZD 122/MWh (now stale at ~NZD 81/MWh per RD_003); Coal $93-313/MWh. This is the only wiki source with NZ plant-level cost data; useful for thesis sector context, not for Lower Moutere community-scale calculation. RD_005

  • MBIE 2021 post-tax real discount rate 4.5% — sits between OT_021’s Germany base (3.2-3.5%) and non-OECD proxy (5.1-5.4%). Calibration anchor for the NZ-WACC recalibration gap (RT_110 still open). For NI community-scale at Lower Moutere, NZ WACC at retail/commercial scale likely sits above MBIE’s utility-scale 4.5% (smaller projects pay higher debt cost). RD_005

Macro analogue of community SS argument (IEA WEI 2026)

  • Clean-energy investment 2015-2024 avoided ~USD 260 bn in fossil-fuel imports in 2025 alone across China, EU, Japan & Korea, Southeast Asia, India. China largest beneficiary (~USD 110 bn avoided). Decomposition: ~⅓ renewables (incl. bioenergy), ~⅓ efficiency (especially transport), ~20% electrification, balance nuclear. This is the macroeconomic version of the I01 community self-sufficiency argument — domestically-deployed clean capacity directly substitutes for imported-fuel cashflows. Use as macro framing for the community SS analysis. OT_025
  • ACCESS scenario community-finance structure: universal electricity access by 2035 = USD 250 bn over the next decade. >55% to grid extension; balance to mini-grids + standalone systems. Equity investment rises 7× to ~USD 3 bn/yr. Mini-grid financing tilts more toward debt + grant; standalone systems ~40% equity (smaller ticket size, higher retail-customer revenue risk). Closest available off-grid / mini-grid community-electrification financing template; informs I01 financial structure assumptions for analogous NZ remote-community pilots. OT_025
  • BESS-as-a-Service (BTM model): customers repay capital via fixed service payment, removing household upfront-capex barrier. Emerging in advanced markets through 2025. Removes the dominant NZ residential battery-finance constraint (CR_008 — no NZ residential battery rebate as of May 2026) by relocating the capex burden from household balance sheet to operator. Material I01 structural option for NZ community deployment. OT_025
  • CREF community co-funding route (EECA): the Community Renewable Energy Fund part-funds community PV+battery (~25% EECA / ~75% partner; ~$88k/site at 28 kW + 32 kWh) at resilience sites (marae/schools/halls) — but it is not openly contestable (needs a regional-authority/iwi partner; community trusts not directly eligible) and is resilience-scale, so a PPA (0-capex, developer-owned) is the more realistic route to community-energy-hub scale (CR_024). One NZ grant route, but not the path to hub-scale self-sufficiency. URL_015

EECA Consumer Energy Monitor Q3 FY25 — NZ household financial behaviour at sub-group level

  • Counter-intuitive finding for higher-bill households (>NZD 200/mo, n=855): under-index on most efficiency actions despite higher bills — closing curtains 64% (vs 67% total), heat only used rooms 58% (vs 62%), cold water washes 57% (vs 63%), turn off appliances 53% (vs 58%). Higher bills correlate with lower efficiency behaviour, not higher — financial signal alone does not drive efficient household action. Direct evidence that community-scale governance / coordination is required beyond price signals, supporting the broader I01 community-finance-as-structural-determinant argument. OT_026
  • NZ supplier-switching behaviour 2025: 51% of NZ bill-payers shopped around or switched electricity supplier in past 12 months. Households with children 56% (highest sub-group); non-homeowners 49%; higher-bill households 55%. Off-peak plan penetration 32% total NZ. Supplier-switching is a working market mechanism at the consumer end — community models that aggregate switching power (e.g. collective procurement) face an already-active retail market. OT_026
  • Non-homeowner under-investment quantified (n=809): LED installed 40% (vs 54% total) — 14-pt gap; draught reduction 35% (vs 44%) — 9-pt gap; 28% have off-peak plan (vs 32%) — 4-pt gap; EV charger off-peak shifting 6% (vs 12%) — 6-pt gap. Landlord-tenant split-incentive problem visible at NZ national scale in the investment-action category specifically (low-cost behavioural actions show smaller gaps). Direct empirical support for the I01 argument that community-housing ownership structure shapes the efficiency-investment decision, and that community models which align owner-occupier incentives (cohousing equity, mixed-tenure cross-subsidy per OT_005) capture efficiency potential that the standard rental market does not. OT_026
  • Households with children — engagement asymmetry (n=941): under-index on behavioural actions (close curtains 63%, heat only used 56%, turn off appliances 53%, cold water washes 61%) but over-index on financial mechanisms: 47% use off-peak power a lot (vs 42% total — highest sub-group), 56% switched supplier (highest), draught-reduction LIFETIME just 38% (vs 44% — significantly lower). Time-poverty correlates with financial-tool engagement and behavioural disengagement — community-scale automation (smart load control, default-on shifting) captures households with children at higher rate than behavioural campaigns. OT_026
  • EECA co-funding = structural financing enabler for NZ community-charger business case: pre-2021 NZ public-charger deployments were 43% subsidy-led (EECA Low Emission Transport Fund + predecessor LEVCF); 2023-2026 deployments (45% of co-funded stock) increasingly gentailer + retail-led building privately atop the EECA-seeded platform. NMT region only 13 co-funded sites (2.5% of national) despite hosting Lower Moutere pilot — regional infrastructure inequality is real. NI community-charger business case at Lower Moutere likely requires EECA co-funding pathway; pure-commercial case unlikely to clear hurdle rates given NMT BEVs-per-co-funded-site ratio of 154 (vs 3.8 national). Funding amounts per site not in register (RT_137 captures this gap). RD_009
  • Per-project co-funding envelope for a community-charger business case (resolves the funding-amounts gap RD_009 flagged at RT_137): the EECA LEVCF register (218 projects, rounds 1–10, 39,992,963 total) shows per-project approved co-funding of **min 5,000 / median 136,567 / mean 183,454 / max 763,668** under the **50%-of-cost, 500,000-cap rule** (11 projects sit exactly at the 500k cap). **18 recipients are District/City Councils** (3,043,713 total, mean $169,095) — confirming a council/community-owned charger is a funded, precedented recipient class, not a novel ask. NI can size a community-charger CapEx case against a real subsidy envelope rather than a guess. OT_119
  • National per-BEV public-kW provision benchmark — updated 2026-05-31 to 2.01 kW per NZ BEV (internally-consistent figure from RD_011: 184.5 MW ÷ 91,900 BEVs; supersedes the prior 1.33 figure derived from cross-source RD_010÷RD_006 which mixed vintages and definitions). For Lower Moutere: at Tasman district rate (1.69% BEVs per capita) 50 HH × 2.6 avg HH size = 130 people → ~2.2 BEVs today; at NZ-target fleet turnover (~25% adoption per RD_006) ≈ ~32 BEVs at fleet replacement. Implied community-target public-kW at 2.01 kW/BEV anchor = ~4 kW (2 BEVs) to ~65 kW (32 BEVs). Tasman district is over-provisioned at 2.31 kW per BEV (above national 2.01), thanks to Kohatu + Murchison corridor sites — a community-owned charger would add marginal capacity above an already-well-served regional baseline. NMT regional benchmark still needs international context (RT_145). RD_011

NZ off-grid microgrid economic viability (Aotea-Great Barrier Island)

  • NZ off-grid microgrid economic viability (Aotea-Great Barrier Island): optimised LCOE NZD 0.09-0.10/kWh vs NZ retail NZD 0.19/kWh, with PI 2.06-2.91%, IRR 17.53-17.93% and discounted payback 7.1-8.4 years across three community systems — community-owned off-grid renewable generation is financially attractive at this island site, though figures are 2021 NZD and exclude inverter/EV-charger costs from the optimisation. LIT_031
  • Coordinated EV charging is a cost lever, not just a grid-service: deferring EV charging to off-peak overnight hours cuts off-grid system TNPC by ~9% (~NZD 38-39k), while ill-timed afternoon charging adds ~20% (~NZD 83k) — demand-side timing flexibility has a directly monetised effect on community capital cost. LIT_031

NZ off-grid community-energy investment case (Rakiura/Stewart Island MECM)

  • NZ off-grid community-energy investment case (Stewart Island MECM): discounted payback period 8.79 years, profitability index 2.45%, internal rate of return 13.68% — a low-risk, high-yield, subsidy-free renewable project. LIT_033
  • The optimised renewable system cuts the diesel-dependent island’s electricity costs by ~54% (0.24 NZD/kWh MECM electricity LCOE vs ~0.52 NZD/kWh current diesel-based cost) if financed as a community project. LIT_033
  • Efficiency-first economics — direct-electrify, don’t build for hydrogen (the cost primary behind LIT_033’s 8.91/kg).** Concept Consulting (2019) finds green H₂ (**8.91/kg NZD grid, 12.56/kg** off-grid) is not cost-competitive with direct-electric use for mass-market end uses at any carbon price: gas→H₂ home heating only turns economic at **650/tCO₂, ammonia-storage peaking needs ~750/tCO₂**, underground-storage peaking has a **~200/tCO₂ fuel-cost floor, and SMR+CCS beats green H₂ up to $500–600/tCO₂. Economic implication for a self-sufficient community: electrify directly and hold hydrogen only for the seasonal/dry-year residual (why LIT_033’s Rakiura design still beats this at 6.97 NZD/kg via on-site opportunistic production). All NZD. OT_122
  • Auditable carbon-price breakevens (Concept 2019, Report 2 — the model behind OT_122’s break-even set). SMR+CCS beats green H₂ up to a 650–1,000/tCO₂ carbon price (75% CCS, power-to-gas green H₂ at 5.3/kg), SMR+CCS becomes competitive with direct natural gas at **350/tCO₂**, and the CCS effective cost is **NZ86/tCO₂**; heavy-transport delivered green-H₂ fuel is NZ10.3/kg current → 6.5/kg future (small-scale), vs a California forecourt price of NZ17.2/kg. Efficiency multipliers: an EV is 1.6× more energy-efficient than a hydrogen vehicle and ~3× less renewable energy per truck — reinforcing the direct-electrify-first economics for a self-sufficient community, hydrogen held only for the seasonal/off-grid residual. OT_151

Community energy-trading metrics and P2P economics (Afzalan & Jazizadeh 2021)

  • Community energy self-sufficiency can be quantified two ways for the economic case: a self-consumption ratio (share of demand met on-site during PV hours, Eq. 3-4) and a complementarity factor CF = 100*|surplus/deficit| (Eq. 2). LIT_034
  • P2P energy trading economics (Swiss field study cited by the authors, Worner et al. 2019): consumers paid peers 0.19 CHF/kWh vs 0.21 CHF/kWh utility price, prosumers set ~0.13 CHF/kWh, yielding ~32% prosumer revenue uplift and ~7% consumer bill saving — order-of-magnitude only, not NZ. LIT_034

Earthsong founder — resale-value capture & the commons (INT_006, NZ primary)

  • The resale-value leak: Earthsong’s company built houses and sold them at cost to shareholders, but when early residents sold at market value they captured the cost-to-market gap as private profit. An interviewee’s position is that this uplift should return to the commons, because a significant proportion of the house price actually funds the common house and land — a first-hand demonstration that a sell-at-cost model alone does not keep collectively-created value in the community. Interview VI [INT_006]
  • Institutional barrier to the fix: other NZ communities that tried to write a commons-clawback clause into their constitution were refused bank finance — “a bank would not lend them funds if there was that kind of clause” — and had to remove it to build. This identifies the specific NZ lending-practice obstacle that blocks the grant-of-use / shared-equity tenure models evidenced in LIT_010 and LIT_015 (RT_190). Interview VI [INT_006]

Household electrification economics (RA Machine Count 2025, NZ)

  • Modelled household electrification (5 NZ archetypes, incl. solar + 5.5% finance on upfront cost) is cost-positive for nearly all types, saving 2,100–12,400 kg CO₂e/yr per household. Net yearly savings: Auckland apartment 358; Dunedin 855; Christchurch 1,239; Wellington 2,718; **Waikato large rural home 3,167** (rural/high-driving homes save most). Nationally, electrifying priority machines saves ~3.7bn/yr (“Ready” tier) + ~$2.4bn/yr (“Almost-ready”) — NZ-grounded electrification-economics anchors. OT_064
  • Value of distributed generation (RA Delivered Cost of Energy 2024): NI economics should value locally-met (self-consumed) load at the delivered cost (wholesale + ~6–13% avoided delivery costs: Dx losses 2–8%, hedging ~5%, deferral) and value exports at wholesale/buy-back — not both at one rate. This asymmetry is what makes battery self-consumption economic and drives the grid-vs-off-grid breakeven. OT_065
  • Farm electrification economics (RA Electric Farms 2024): Forest Lodge Orchard saves >40,000/yr + ~20,000/yr export = ~60,000/yr additional profit; the 40k/yr saving services $400k debt @5.5% over 15 yr; emissions −93% (54→4 t CO₂e). Rooftop solar at 6.2–11.5c/kWh vs grid 33.9c/kWh is the cheapest delivered energy — the cost-stack basis for self-sufficiency economics. OT_066
  • National + household electrification economics (RA Investing in Tomorrow 2024): NZ spends ~19.84bn/yr on (mostly imported) fossil fuels; household electrification saves ~1,485/yr (5.5% finance) to ~4,699/yr (1%) per home, ~10.7bn/yr nationally by 2040 ($95bn cumulative). Local generation hedges fossil-price volatility + improves the balance of trade — the macro argument for energy self-sufficiency. OT_067
  • Export-valuation parameter (RA Symmetrical Export Tariffs 2024): a self-consumed kWh avoids ~33c/kWh delivered cost; an exported kWh earns only ~12c (buy-back) today → self-consumption is ~3× more valuable than export. This asymmetry is the economic driver of on-site battery sizing in the SSI/D21 logic (value local-met load high, exports low). OT_068
  • The price + capex data layer behind the savings figures (RA Machine Count DATABASE, OT_153). OT_064’s household/farm savings numbers rest on this workbook’s transparent assumption table: fuel prices petrol 269.98 c/L, diesel retail 199.2 c/L (commercial 157.25); electricity residential 0.34254/kWh** (commercial 0.21336 / agricultural 0.24048 / industrial 0.17795), natural gas residential **0.1767/kWh, LPG residential volume 0.3088/kWh**, wood **0.113/kWh; RUC BEV/diesel **0.076/km**. Paired with fossil-vs-electric **capex** per machine (barbecue 549→859; residential cooking oven 1,310→599; commercial cooking oven 9,660→$10,982), these are the cost inputs behind the household net-savings figures — candidate cross-checks for the NI electricity-tariff and bought-fuel cost cells (against RD_018 / OT_106), applied to no cell here. ⚠ RA’s own dated assumptions, not a government price series. OT_153

Grid-tied community-MG economics — Ohakune (Mohseni et al. 2021)

  • A grid-tied, 100%-renewable community micro-grid for Ohakune optimises to LCOE 0.08/kWh (2019 USD) vs a site retail price of 0.22/kWh → “savings of at least 64% in the community’s energy costs” if community-owned (whole-life cost $21.72m at a 20-year life / 3.7% real interest rate). A grid-tied NZ analogue to the islanded Mohseni cases (Totarabank LIT_032, Great Barrier LIT_031, Stewart Island LIT_033), reinforcing that community-owned renewable generation lands well below NZ retail. LIT_067

NZ household energy-expenditure baseline (Riggs, Isaacs & White 2023, HES/IDI)

  • NZ-representative household energy bill ≈ 2,328/yr** (all-months, HES-weighted incl. supply charges; **2,589 cold-months, **2,026** low-income), of which **electricity is ~85%** (~1,958/yr all-months); the NZ residential price rose 19→29 c/kWh (2006→2021), ~+1 c/kWh/yr to 2015 then flat. A direct NZ input for the model’s household energy-OpEx line and electricity-tariff assumption — an actual-spend (HES/IDI microdata) baseline distinct from the advertised retail-price series (RD_018) and the modelled per-dwelling energy figures. OT_106

Value of a peak-shaving battery = avoided network capex (Aurora AMP 2024, Upper Clutha DER)

  • A second NZ DSO frames consumer-battery value as deferred subtransmission capex, not a headline tariff. Aurora’s 2024 AMP states non-network (flexibility) solutions “enable deferral of much greater capital expenditure … lower lifecycle cost”, citing its solarZero solar-battery + hot-water partnership as deferring investment on the constrained Upper Clutha 66 kV circuit (firm winter capacity 33 MVA, N-1 voltage-limited). This corroborates the RT_233 Orion network-value premise (~77/kVA at coincident peak) with a South-Island DSO example — but the AMP does **not** publish the /kWh reward rate (that is in Aurora’s separate Pricing Methodology, RT_359), so it grounds the value cell’s rationale, not its number. OT_109

Network-value of a peak battery = the $77/kVA LRAIC, primary-sourced (Orion Pricing Methodology 2024; resolves RT_233)

  • The economic-value layer the Aurora cluster above points to, now primary-sourced. Orion’s Appendix G derives a coincident-peak LRAIC of 77/kVA/year** (69 upper-HV + 8 lower-LV) — the gross avoided-network-cost a peak-reliable community battery could in principle capture — but Orion's **realised export credit is only "approximately a third" of it** (§7.1; scheduled credits 0.28 c/kWh anytime, 0.95 c/kWh peak, **0 c/kWh** for PV on monthly-only metering). The ~3× gap between the **gross 77/kVA/yr deferral value and the ~⅓ realised credit is the I01 decision for any peak-battery payback: value the deferral at $77/kVA/yr only as a social/avoided cost — a NZ generator is actually paid ~⅓ today. Corroborates OT_109’s “value = deferred network capex, not a headline tariff” with the Orion primary and its full derivation. OT_125
  • **A peak-export battery’s value on Aurora’s network is an avoided demand charge, not a payment — and the “1.50/kWh" was never an Aurora rate.** Aurora's *Pricing Methodology* (1 April 2024) confirms Aurora **makes no payments to DG owners** (para 185); the value of exporting at peak is the **CPD demand charge a connection avoids** by lowering its assessed CPD kW (the Upper Clutha/Wānaka trial credits 50% of CPD-period export into average CPD kW, para 95). So the RT_235 "~1.50/kWh reward” (OT_066) is best read as the effective value of that avoided demand charge for one ≥69 kVA connection — derived, not published; any NI use must derive it from the CPD price (¢/kW/day) × Control-Period days × 0.5, not read it off. Aurora’s LRMC of peak capacity (107–882/kW by pricing area) corroborates OT_109/OT_125 that the value driver is deferred peak-capacity investment; it is the Aurora end of the still-open national bound (RT_360). OT_163

NZ community-energy co-funding availability (MBIE Budget 2023 CERF bid)

  • Establishes a primary government commitment to grants/co-funding for small-scale community renewable projects targeting low-income and energy-insecure communities, MBIE-administered via multiple procurement rounds — the Budget 2023 CERF bid sought a 30m** programme boost (26.5m grants + 3.652m admin/2 FTE) plus **20m innovation. Substantiates the CREF co-funding lever in the NI financial layer (a community’s effective CapEx reduced by grant support shown here to be a funded, ongoing national programme; ~25% EECA co-funding per URL_015). ⚠ Envelope only — no per-site cost. OT_120

  • CREF Round 2 co-funding allocation (EECA; Round 2 announced July 2025, allocation PDF authored 10 Sep 2025): 22 regional partners share 9.6M EECA co-funding + 3.2M partner commitment = a 12.8M pool; per-partner EECA amounts 132k–1.188M. The delivery-stage granular counterpart to [[ot_120_mbie-cref-energy-resilience-2023|OT_120]]'s Budget-2023 envelope and [[url_015_eeca-cref-community-renewable-fund|URL_015]]'s aggregate — a concrete national NZ community-finance route for the CREF co-funding lever ([[cr_024_nz-community-pv-battery-cost-2026|CR_024]], which also carries the CREF **28M total-commitment** figure — the programme-wide total, distinct from this $9.6M Round 2 allocation). Programme EECA:partner split ≈ 75%:25% — NB this is the EECA-to-partner pool split, NOT the ~25% per-site grant proportion; see OT_150 Notes for the URL_015 ratio discrepancy to reconcile. No per-site CapEx. OT_150

Dancing Rabbit land-trust economics (Lockyer 2017 — qualitative model, no cost figures in this source)

  • Dancing Rabbit land-trust economics (Lockyer 2017, qualitative model, no cost figures in this source): the leasehold model de-commodifies land (monthly lease fee, members own only on-plot improvements → “no ability to speculate … permanently affordable”), cooperatives socialise infrastructure cost (showers, laundry, internet, utilities, a four-vehicle co-op), and an internal community currency (ELMs) circulates. An affordability/economic-sufficiency mechanism; DR cost-of-living figures (rent $150–450/mo) come from LIT_012, not here. LIT_081

EDT connections

[Which EDT domains most directly advance this indicator, and how.]

Measurement

  • Debt-to-equity ratio and internal capital management CR_001
  • Per capita income level and ratio of dependence on external aid CR_001
  • Local budget self-sufficiency ratio and tax revenue independence score CR_001
  • Diversification of products, markets, and investment portfolios CR_001

Open questions

[Gaps in evidence, unresolved tensions, links to questions/ pages.]

Connections

Links to

Sources (59): CR_001 · CR_008 · CR_011 · CR_024 · LIT_001 · LIT_002 · LIT_003 · LIT_005 · LIT_006 · LIT_010 · LIT_012 · LIT_014 · +47 more

Concepts (2): EDT–SSI Convergence · Self-Sufficiency Calculation Framework

Referenced by

Sources (12): LIT_003 · LIT_004 · LIT_005 · LIT_006 · LIT_075 · OT_004 · OT_005 · OT_025 · OT_106 · OT_109 · OT_119 · OT_163

Graph View

Backlinks