Source
https://doi.org/10.1016/j.apenergy.2021.116563 — original source (opens in a new tab; the file is not redistributed)
Mohseni et al. 2021 — Ohakune multi-energy-storage micro-grid (LIT_067)
A 4th NZ Mohseni community-micro-grid cost anchor — and the only grid-tied one
A notional grid-tied, 100%-renewable micro-grid for the mountain town of Ohakune (central North Island). Delivers a full per-technology CAPEX table (2019 USD), a whole-life-cost decomposition, a cost-optimal equipment sizing, and an LCOE of $0.08/kWh — the fourth NZ community-MG techno-economic study from the Mohseni/VUW group, sitting alongside the islanded Great Barrier (LIT_031), Totarabank (LIT_032) and Stewart Island (LIT_033) cases.
Summary
Mohseni et al. (2021, Applied Energy 287:116563) develop a customer-comfort-aware, demand-response (DR)-integrated long-term micro-grid (MG) capacity-planning optimisation model, and apply it to a notional grid-tied, 100%-renewable MG for the town of Ohakune, New Zealand (lat 39.4180°S, lon 175.3985°E). The MG couples PV, wind, micro-hydro, a biopower (pellet) plant, a fuel cell, a battery bank, a super-capacitor bank, and power-to-gas hydrogen storage with a light-duty hydrogen FCEV vehicle-to-grid (V2G) fleet. A two-stage (wholesale + retail) game-theoretic demand-side-management market is used to project responsive-load participation. The cost-optimal system has a levelised cost of energy of 0.08/kWh** (2019 USD) and a whole-life cost of **21.72 m, against a site retail price of 0.22/kWh** — implying ≥64% community energy-cost savings if community-owned. Modelling the DR market cuts whole-life cost by **21% (~US5.5 m) vs a business-as-usual interruptible-DR plan and by 32% (~US$10 m) vs no DR. The paper’s main NI value is its NZ-market component cost table and its whole-life-cost/sizing breakdown for a mixed multi-storage community system.
Key claims
- claim: "CASE STUDY IDENTITY & ARCHITECTURE. A NOTIONAL, grid-tied (grid-connected) micro-grid designed to achieve 100%-renewable energy GENERATION for the town of Ohakune, central North Island, New Zealand (latitude 39.4180°S, longitude 175.3985°E; temperate climate, high seasonal load). Component set optimised = photovoltaic panels (PV) + wind turbines (WT) + micro-hydro (MHPP) + biopower/pellet plant (BP) + fuel cell (FC) + battery bank (BESS/B) + super-capacitor bank (SC), plus power-to-gas hydrogen storage (electrolyser → hydrogen tank → fuel cell) and a light-duty hydrogen fuel-cell electric-vehicle vehicle-to-grid fleet (FCEV2G). The upstream grid 'serves as the ultimate guarantor of the perfect satisfaction of the electric load demand' — i.e. grid-tied with grid as backstop, NOT islanded."
source_location: "Abstract; Section 5.1 (case study site); Table 11 (system architecture row); Nomenclature (component set C); Section 2.2 operational strategy (grid as ultimate guarantor)"
- claim: "HEADLINE LCOE & COMMUNITY SAVINGS (verbatim). 'By solving Eq. (49), the LCOE of the proposed MG is found to be $0.08/kWh, while the most recent yearly average retail price of electricity is as high as $0.22/kWh at the studied site. That is, implementing the proposed MG system is expected to realise savings of at least 64% in the community's energy costs if financed as a community-owned renewable energy project.' Both figures are 2019 USD; $0.08/kWh ≈ NZ$0.125/kWh at the paper's Oct-2019 rate US$1 = NZ$1.56."
source_location: "Section 5.3.1 (financial appraisal); Eq. (49)"
- claim: "WHOLE-LIFE COST & DEMAND-RESPONSE SAVINGS. Whole-life cost (WLC) of the cost-optimal MG (market-based MBI-DR case) = $21.72 m (2019 USD). The proposed market-based DR integration reduces the estimated whole-life cost 'by at least 21% and up to a maximum of 32% (with an incentive resolution of $0.02/kWh)' vs the business-as-usual (BAU) interruptible-DR and the non-DR (NO-DR) planning cases respectively — a saving of ~US$5.5 m (21% vs BAU $27.3 m) and ~US$10 m (32% vs NO-DR $31.81 m). Financial appraisal used a 20-year project life and a 3.7% real interest rate; peak system load PL,max = 7.31 MW."
source_location: "Section 5.3.1 (WLC $21.72 m); text after Table 10 (21%/32% range); Abstract & Conclusions insight 1 (~US$5.5 m) and insight 2 (~$10 m); Section 4 / p.16 (20-yr life, 3.7% real interest); Table 2 (PL,max 7.31 MW)"
- claim: "WHOLE-LIFE COST HEADLINES (Table 9, 2019 USD, discounted over 20 yr; MBI-DR / BAU-DR / NO-DR). Whole-life cost 21.72 m / 27.3 m / 31.81 m; equipment-related costs dominate (18.25 m / 21.88 m / 25.62 m) and discounted electricity imports collapse under market-based DR (0.46 m vs 7.46 m NO-DR). The full component-line breakdown is in the source table, not reproduced here."
source_location: "Table 9 (Breakdown of the total discounted system cost under different DR provision strategies)"
- claim: "OPTIMAL EQUIPMENT SIZING, MBI-DR headline set (Table 10): PV about 1.01 MW; wind 3.0 MW (4 x 750 kW); micro-hydro 600 kW; battery bank 3,400 kWh; hydrogen tank 6,079 kg; electrolyser 610 kW; fuel cell about 785 kW. Full module-level sizing, minor components, and the BAU/NO-DR scale-ups are in the source table, not reproduced here."
source_location: "Table 10 (Size of the MG equipment in the cost-minimal solution); Table 3 (nameplate ratings)"
- claim: "EQUIPMENT COST-DRIVER RANKING (Table 10 STDEC%, MBI-DR): wind 24.11% is the largest single driver, then battery 17.49%, hydrogen tank 16.93%, super-capacitor 14.53%; storage plus the hydrogen chain together exceed 45% of total discounted equipment cost. The full 13-component ranking is in the source table, not reproduced here."
source_location: "Table 10 (STDEC* rows; STDEC = share of total discounted equipment-related costs)"
- claim: "COMPONENT TECHNO-ECONOMIC UNIT COSTS, NI-relevant subset (Table 3; capital costs are 'the actual cost of buying the selected components in New Zealand's energy asset market as of October 2019', 2019 USD, US$1 = NZ$1.56). PV $750/kW (η 17.11%, 25 yr); wind $1.46 k/kW (750 kW class, 20 yr); micro-hydro $560/kW (100 kW class, η 78%, 25 yr); battery (LFP) $901-1,100/kWh by pack size (η 80%, 20 yr); electrolyser $1.2 k/kW (η 75%); fuel cell $1.52 k/kW (η 40%); hydrogen tank $500/kg; super-capacitor $24.1 k/kWh; FCEV2G outlet retrofit $155/kW (η 44%). The remaining component rows and per-unit O&M columns are in the source table, not reproduced here."
source_location: "Table 3 (Data values and sources for techno-economic specifications) and its notes * (NZ Oct-2019 prices, US$1 = NZ$1.56)"
- claim: "DEMAND-RESPONSE / DEMAND-SIDE IMPACT. Relative to the NO-DR case, the market-based (MBI) DR shaves ~38% off maximum peak power demand and the BAU DR shaves ~24%; this lifts the annual load factor from 0.25 (NO-DR) to 0.31 (BAU) and 0.35 (MBI). Penetration levels of light-duty FCEVs and heat pumps were assumed at 40% and 60% respectively at time of commitment (heat-pump uptake tied to the NZ 'Warmer Kiwi Homes' up-to-90% heat-pump grant); morning/evening peaks assumed at 6–10 a.m. and 5–9 p.m."
source_location: "Section 5.3 (results item 4/5: peak shaving ~24%/~38%, load factor 0.25→0.31→0.35); Section 5.2 (40% FCEV / 60% heat-pump penetration, Warmer Kiwi Homes)"
- claim: "LCOE BENCHMARK (Table 11, unsubsidised 2019 USD/kWh): this study's 0.08 is 'highly competitive with the best value reported in the recent literature for a community-scale, 100%-renewable electrification project'; the comparable schemes in the table span 0.06 (Egypt PV/FC) to 1.60 (Iranian villages). Inclusion criteria: self-sufficiency ratio of at least 85% if grid-connected, 100% renewable, small-to-medium-community electrification. The full seven-study comparison is in the source table, not reproduced here."
source_location: "Table 11 (Comparative evaluation of the proposed MG's LCOE); Section 5.3.1 (benchmark criteria + competitiveness statement)"
- claim: "MICRO-HYDRO & KEY MODEL PARAMETERS. Micro-hydro modelled at gross head hg = 10 m, rated 100 kW/turbine, AC/DC-converter-inclusive efficiency ηMH 78%, streamflow-driven (river streamflow F(t) [m3/s]) — directly relevant to NI micro-hydro feasibility (head 5–10 m band). Other scalars: export/feed-in tariff πex = $0.05/kWh; biomass pellet feedstock $72/tonne of pellets; carbon price ξCO2 = $42/tCO2 for 2020–2030 rising to $50/tCO2 for 2030–2040; wind hub height h = 55 m; HHV of hydrogen 39.7 kWh/kg; biopower CO2 emission factor 1.53 kg-CO2/kg-feedstock."
source_location: "Table 2 (hg 10 m, πex $0.05/kWh, ξCO2 $42/$50, h 55 m, HHVH2 39.7 kWh/kg, ECO2 1.53); Table 3 (micro-hydro $560/kW, η 78%, 100 kW); Section 5.3 ($72/tonne pellets)"Neobiome Intelligence relevance
The primary NI value is the NZ-market component cost table and the multi-storage whole-life-cost/sizing decomposition. Table 3 gives per-technology capital / O&M / service-life / efficiency values priced from the actual NZ energy-asset market (Oct 2019) — a NZ-grounded cross-check on the engine’s cost cells: micro-hydro 560/kW** (≈ NZ875/kW, far below the OT_062 8–30k/kW small-hydro band because this is a 100 kW class turbine, not micro), PV **750/kW module-only, battery 901–1,100/kWh**, fuel cell **1.52 k/kW, electrolyser $1.2 k/kW. These are 2019 USD (×1.56 → NZD) and should be read as a dated benchmark, not a live figure.
LCOE cross-check for the community-MG envelope (I01/D01). The optimised LCOE 0.08/kWh (2019 USD) ≈ NZ0.125/kWh slots the wiki’s NZ community-MG LCOE ladder: just above the eco-village cluster (Totarabank NZ0.094, [[lit_032_mohseni-2020-totarabank|LIT_032]]; Great Barrier NZ0.09–0.10, LIT_031) and well below the diesel-displacement end (Stewart Island NZ$0.24, LIT_033). Unlike those islanded cases, Ohakune is grid-tied with the grid as ultimate backstop — the closest NZ analogue to a grid-connected-but-highly-self-sufficient community (the NI default design per CR_030).
Multi-storage allocation by timescale (D01). The system splits storage across super-capacitor (transient) / battery (intra-day) / hydrogen tank+fuel cell (seasonal) via an energy-filter approach, with biopower as the only dispatchable generator for seasonal load-levelling. The cost-driver ranking (wind 24% > battery 17.5% > hydrogen tank 17% > super-capacitor 14.5%) is a useful structural signal: the storage + hydrogen chain is >45% of equipment cost, and the super-capacitor’s very high /kWh (24.1 k/kWh) confirms it is a power- not energy-buffer.
Seasonal-load design lesson (I06/I07). Ohakune’s high seasonality (winter high season, June–August) is met by filling the hydrogen tank gradually Oct→June for winter fuel-cell dispatch — a worked example of inter-seasonal hydrogen storage for a seasonal-demand mountain community, and support for the DR/peak-shaving lever (MBI DR shaves ~38% of peak, lifts load factor 0.25→0.35).
Hydrogen mobility (D05) is research-horizon for NI. The FCEV V2G integration (40% penetration, Riversimple Rasa, 155/kW V2G-outlet retrofit, 44% tank-to-DC-bus efficiency) is a minor cost/value line here (~0.4–0.5 m of the 21.72 m WLC; 0.57% STDEC) and aligns with CR_030’s read that hydrogen for community energy is research-horizon — record as illustrative, not calibration.
Research targets
Documents to retrieve
- RT_355 (doc, low priority) — Mohseni et al. (2021) Applied Energy Supplementary Material (Additional Files 1–4: key life-cycle-analysis assumptions; full Ohakune case-study details on climate/load/wholesale-price profile derivation; Table S1 backup-power-sale sensitivity; seasonal DR statistical analysis). Only worth retrieving if an Ohakune case page is built — the main paper already carries the full cost table and sizing. [NI]
Research gaps
- None new. The NZ retail-price and national-benchmark gaps this paper touches are already covered (RD_018 retail; OT_075 / OT_062 micro-hydro cost/CF). The component costs are 2019 USD and dated — the live NZ community-scale cost work is CR_024.
Notes
Primary peer-reviewed article (Applied Energy 287:116563, doi:10.1016/j.apenergy.2021.116563), read verbatim via pdftotext — data_quality: verified. Notional/conceptual optimisation study, not a built system — LCOE and costs are simulation outputs (same status as the sibling Mohseni NZ studies). All monetary values are 2019 USD (Oct 2019 US1 = NZ1.56); multiply by 1.56 for NZD comparability with the rest of the wiki. context: ni (the energy-democracy / community-ownership framing would also support both, but the calibration value is the cost data). ⚠ Borderline new page: Ohakune is central to this one source — an ohakune case page could be justified (as with the other Mohseni cases); flagged for a project decision rather than drafted here.
Connections
Links to
Referenced by
SSI indicators (3): I01: Financial & Economic Self-Sufficiency · I06: Resistance to External Shocks · I07: Fulfilment of Basic Needs
EDT domains (2): D01: Renewable Energy & Storage Systems · D05: Smart Mobility & Electrified Transport