Source
http://web.archive.org/web/20210129080423/http://www.concept.co.nz/uploads/2/5/5/4/25542442/h2_report2_analysis_v4.pdf — original source (opens in a new tab; the file is not redistributed)
Concept Consulting (2019) — Hydrogen in New Zealand, Reports 2 (Analysis) & 3 (Background Research)
The two technical volumes behind OT_122 (Report 1 – Summary). Report 2 – Analysis (86 pp) is the full bottom-up techno-economic cost model — it decomposes the **
8.91/kg NZD** green-hydrogen reference into its components (wholesale electricity4.88 + electricity network1.91 + electrolyser capex1.03 + opex0.59 + storage0.50 per kg), publishes the core input-assumption set (electrolyser1,400/kW →700 future, 70% efficiency, 85% utilisation, wholesale electricity0.075/kWh, storage0.5/kg-H₂), and gives the full use-case cost matrix (current6.80–12.56/kg) plus the SMR+CCS model and carbon-price breakevens. Report 3 – Background (53 pp) is the hydrogen-technology reference — production routes, storage technologies and costs (compressed gas ~$7,000/GJ of storage capacity), distribution, CCS, ammonia as a carrier, and the Leeds City Gate H21 conversion case.⚠ RT_166 residual resolved. These reports were retrieved to close the open leg of RT_166 — whether a “14 NZD/kg (small-scale)” green-H₂ production figure (attributed to “Concept Consulting 2019” by LIT_033) exists in the technical volumes. It does not: Report 2’s full-model use-case matrix (Table 3) has the same highest current value as Report 1 — **off-grid bulk storage
12.56/kg** — and no14/kg green-hydrogen production cost appears anywhere in either volume.
Summary
Reports 2 and 3 are the analytical and background volumes of Concept Consulting’s three-part Hydrogen in New Zealand study (Jan 2019), the summary of which is held as OT_122. Report 2 – Analysis builds the bottom-up cost models that generate every headline figure in the Summary: a green-hydrogen supply-chain model (grid electricity cost + electrolyser/storage capital + process losses), a hydrocarbon (SMR+CCS) model, and end-use competitiveness models for heavy transport, industrial process heat, space/water heating, power generation and export. Its Table 1 sets out the core green-hydrogen assumptions and resolves the $8.91/kg reference into its five cost components; Table 3 spreads production cost across five use-cases and three scenarios (current / future-opportunistic / future-large-scale); Table 4 gives the SMR-vs-green carbon-price breakevens. The report also models the optimisation of production — running electrolysers at lower utilisation to chase low-price “opportunistic” electricity — and finds a flat “bath-tub” cost curve with an optimum around 80% utilisation.
Report 3 – Background Research is the technology reference: hydrogen production (electrolysis, SMR), the four storage routes (compressed gas, cryogenic liquid, chemical bonding, metal hydride) and their costs, distribution (pipeline, compressed-gas trailer, cryogenic, ammonia carrier), hydrogen end-uses, safety, gas-network blending, carbon capture and storage, ammonia technology, the UK Leeds City Gate H21 town-conversion case study, and a survey of worldwide hydrogen programmes. For Neobiome the load-bearing content is the storage-technology detail and storage costs (compressed-gas storage ~**7,000/GJ** of capacity; state-of-the-art class-IV tanks; metal hydride "not yet ready to be used commercially") that sit behind the seasonal-storage question, plus a real, costed town-scale conversion (Leeds H21: 1,025 MW production, ~NZ767M capital ≈ $750,000/MW). Together the two volumes are the primary techno-economic backing for the NZ green-hydrogen figures NI carries — and they confirm the Summary’s central finding that direct electrification beats hydrogen for mass-market end-uses at any carbon price, hydrogen’s niches being remote off-grid supply, return-to-base freight and high-carbon-price seasonal peaking.
Key claims
- claim: "Report 2 Table 1 — Core green hydrogen model cost assumptions ($NZ, excl. GST), [Current | Future]: Electrolyser $1,400/kW | $700/kW (future reduction = 3.4%/yr for 20 yr); Opex 5% | 5% of capex/yr; Useful life 20 | 20 yr; Discount rate 6.0% | 6.0%; Electrolyser efficiency 70% | 70%; Compression losses 10% | 10%; Assumed utilisation factor 85% | 85%; Storage cost $0.5/kgH2 | $0.35/kgH2; Storage cycles 365 | 365 /yr; Wholesale electricity $0.075/kWh | $0.075/kWh; Electricity network losses 4.0% | 4%; Electricity network cost $0.031/kWh | $0.014/kWh. Resultant costs ($/kgH2), [Current | Future]: Electrolyser capex 1.03 | 0.51; Electrolyser opex 0.59 | 0.29; Storage 0.50 | 0.35; Wholesale electricity 4.88 | 4.88; Electricity network 1.91 | 0.90; TOTAL 8.91 | 6.94; (= 62.7 $/GJ | 48.9 $/GJ). Wholesale electricity is the single largest component ($4.88 of $8.91)."
source_location: "Report 2 – Analysis, Section 2-1.2 Green Hydrogen Cost Model, Table 1 (rendered image), printed p.11"
- claim: "Report 2 Table 3 — Estimated hydrogen production costs for different use-cases ($/kgH2), columns [Current | Future Opportunistic | Future Large-scale]: Gas Dx injection 7.57 | 2.97 | 5.93; Gas Tx injection 6.80 | 2.67 | 5.33; Bulk storage 8.91 | 4.65 | 6.94; Service station 11.30 | 6.55 | 9.11; Off-grid bulk storage 12.56 | 9.22 | 9.22. [Table source note: Tech_Eval_v05.xlsm. This full-model matrix is identical to Report 1's Table 1 — the highest CURRENT figure is off-grid bulk storage 12.56 $/kg; NO figure of 14 $/kg green-hydrogen production cost appears anywhere in Report 2 or Report 3.]"
source_location: "Report 2 – Analysis, Section 2-1.2, Table 3 (rendered image), printed p.25; cross-check Table 2 (opportunistic, current+future) printed p.23"
- claim: "Off-grid use-case drivers (why off-grid bulk storage is the most expensive current case at $12.56/kg): off-grid avoids electricity network costs but incurs (a) larger storage costs — the generation variability of a single wind-farm or solar panel is much greater than New Zealand's whole grid-connected renewable fleet, requiring a much larger store to deliver similarly reliable hydrogen; and (b) lower electrolyser capacity factors — a capacity factor based on solar generation of ~20% is assumed (a relatively large-scale single-axis-tracking, winter-oriented solar facility; smaller-scale static solar facilities are more likely to achieve ~15%), versus 85% for the other use-cases, so electrolyser capital-recovery cost per kg is much higher. Concept's assessment: off-grid solutions are generally only really cost-effective where the electricity network costs of getting a grid connection are much higher than the modelled levels — e.g. a remote rural location needing a dedicated electricity spur line."
source_location: "Report 2 – Analysis, Section 2-1.2 (use-case descriptions + footnotes 9 & 11), printed pp.13–14"
- claim: "Production-cost optimisation: modelling the trade-off between chasing low-price 'opportunistic' electricity (lower utilisation) versus spreading capital and network charges (higher utilisation) produces a flat 'bath-tub' cost curve, with an optimal utilisation around 80% — very close to the 85% base-case value — and relatively little variation in total cost between 30% and 80% utilisation. Low-cost opportunistic production is only valid for small-scale hydrogen production that does not drive new renewable build; at a scale material to NZ transport or process-heat demand the price collapses that enable it would not persist, and the wholesale-electricity component reverts toward the cost of building new generation (with projected average wholesale prices ~10% higher under large-scale hydrogen-driven renewable development)."
source_location: "Report 2 – Analysis, Section 2-1.2 (Figures 11–17, 'Optimising hydrogen production costs'), printed pp.14–24"
- claim: "Hydrogen from hydrocarbons (SMR + CCS): Concept's modelled SMR+CCS production cost is approx. $14/GJ (excluding carbon costs, with CCS), consistent with international estimates; the effective cost of the CCS is NZ$86/tCO2. SMR produces 40 kg CO2 per GJ of hydrogen; the base case assumes 75% of CO2 captured, giving SMR+CCS one-third of the emissions of using natural gas directly. ⚠ CLARIFICATION (edit 2026-07-20): the '$2.7/kg = $19/GJ' figure that earlier framings placed here is NOT the SMR cost — Concept's modelled SMR+CCS production cost is ~$14/GJ (≈ $2/kg); the $2.7/kg = $19/GJ value corresponds to a green-hydrogen production figure (≈ the Table 3 future-opportunistic Gas-Tx-injection $2.67/kg), not a hydrocarbon/SMR estimate. Table 4 carbon-price breakevens ($/tCO2), by % CO2 removed by CCS [60% | 75% | 90%] and a $10/GJ-gas sensitivity (75% CCS): SMR+CCS competitive with SMR 108 | 86 | 72 ($115 at $10/GJ gas); SMR+CCS competitive with direct natural gas 502 | 350 | 270 ($430); Green hydrogen (power-to-gas, $5.3/kgH2) competitive with SMR+CCS 650 | 1,000 | 2,600 ($670)."
source_location: "Report 2 – Analysis, Section 2-2.2 Hydrocarbon-Based Hydrogen Cost Model, Figure 20 + Table 4, printed pp.26–28"
- claim: "Heavy-transport delivered fuel cost (green hydrogen, including service-station overheads): current delivered cost NZ$10.3/kg, falling to NZ$6.5/kg in a future with small-scale hydrogen uptake, or NZ$9.1/kg in a future with large-scale uptake driving new renewable generation. If per-kg service-station cost recovery were double under small-scale uptake, the future cost would rise from NZ$6.5/kg to NZ$7.8/kg. For comparison, the cheapest forecourt hydrogen currently sold in California is NZ$17.2/kgH2 (excl. sales tax). Efficiency: an EV is 1.6 times more energy-efficient than a hydrogen fuel-cell vehicle (fuel-cell efficiency assumed 55%), and almost three times as much renewable energy is required to power a hydrogen truck as a battery-electric truck (73% ÷ 25% = 2.9); EV fuel costs are almost inevitably substantially less than HV fuel costs."
source_location: "Report 2 – Analysis, Section 3-1.2 Heavy Transport Cost Model (Fuel cost) + Figures 29–31, printed pp.42–44"
- claim: "Report 3 storage technologies and costs: four storage routes assessed — compressed gas (cylinders/tanks; state-of-the-art class-IV carbon-fibre tanks are expensive; the lowest-energy-input option for small amounts), cryogenic liquid (denser but with unavoidable boil-off and cryogenic-treatment cost), chemical bonding (e.g. ammonia/toluene carriers), and metal hydride (a metal matrix that adsorbs pressurised hydrogen — 'not yet ready to be used commercially, and therefore is not considered further'). Where only a small amount of storage is required, compressed-gas storage is practical at the order of $7,000 per GJ of storage capacity."
source_location: "Report 3 – Background Research, Section 3 Hydrogen storage (3.1–3.5), printed pp.7–9"
- claim: "Report 3 hydrogen distribution costs: a hydrogen transmission pipeline costs $1M–$2M per km to construct (excl. intermediary compressors); compressed-gas tube-trailer tanks cost around $7,500 per GJ of capacity today, falling to ~$6,200/GJ before 2030 (high price partly reflecting carbon-fibre cost ~$170/kg wholesale). For delivery of 20 TJ of hydrogen per year to a site 100 km from the production facility — i.e. a 200 km round trip (the '200 km round-trip' is the round-trip distance to a site 100 km away, not a 200 km delivery radius) — delivering the hydrogen as a compressed gas works out at $7.51 per GJ, whereas delivering the same energy as ammonia costs $1.41 per GJ; delivery of large quantities as a cryogenic liquid has been estimated up to four times cheaper per GJ than compressed gas."
source_location: "Report 3 – Background Research, Section 4 Hydrogen distribution (4.1 Distribution costs, delivery to a site 100 km from production / Figure 2 '200 km round-trip'), printed pp.10–13"
- claim: "Report 3 Leeds City Gate H21 case study (UK town-scale gas-to-hydrogen conversion): a production capacity of 1,025 MW with construction cost estimated at NZ$767 million — just under $750,000 per MW of production capacity — plus a budgeted NZ$60 million per year for infrastructure management. A hydrogen fuel-cell combined-heat-and-power unit (including heat output, assuming 50,000 units built) is estimated at around NZ$1,865/kW."
source_location: "Report 3 – Background Research, Section 10 Leeds City Gate: H21 hydrogen conversion study (10.5 Costs) + Section 5.1 Electricity generation, printed pp.35–40, p.14"Neobiome Intelligence relevance
These are the technical volumes that stand behind the NZ green-hydrogen figures NI already carries via OT_122 and LIT_033. Their value is that they turn OT_122’s headline numbers into an auditable model — and they close the RT_166 residual.
- The full green-H₂ cost model behind the
8.91/kg (D01 / hydrogen_storage).** Report 2's Table 1 is the input-assumption set and per-component decomposition NI needs if it ever recalibrates the 2019 benchmark to current prices: electrolyser **1,400/kW (→700 future), **70%** electrolyser efficiency, **85%** utilisation, storage **0.5/kg-H₂**, wholesale electricity0.075/kWh**, network **0.031/kWh — producing8.91/kg as electricity4.88 + network1.91 + electrolyser capex1.03 + opex0.59 + storage0.50 OT_151. Because electricity is more than 75% of the cost (wholesale4.88 = 55% + network1.91) and all equipment (electrolyser + storage capital & operating) only ~24%, the single most important lever for a lower NZ green-H₂ cost is cheap surplus renewable electricity, not electrolyser capex — the exact signal a Neobiome community’s on-site-surplus electrolyser (like LIT_033’s) is built around. The off-grid drivers (a ~20% solar-based electrolyser capacity factor, ~15% for smaller static solar, and larger storage for single-site variability) explain the $12.56/kg off-grid figure and set the realistic upper anchor for a remote community running its own electrolyser OT_151. - Storage technology + storage cost detail (hydrogen_storage / D01). Report 3 gives the four storage routes and their maturity — compressed gas and cryogenic liquid commercial, chemical bonding via ammonia/toluene, metal hydride “not yet ready to be used commercially” — plus a storage-capacity cost of ~$7,000/GJ for compressed-gas storage OT_151. This is the technology-and-cost substrate under the
hydrogen_storagepage’s seasonal-storage question, and a NZD-denominated cross-check on the international storage figures the page currently carries from CR_030/CR_040. - Carbon-price breakevens and the direct-electrify economics (I01 / thesis). Report 2 supplies the auditable version of 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), SMR+CCS becomes competitive with direct natural gas at350/tCO₂**, and the CCS effective cost is **NZ86/tCO₂ OT_151 — and the transport-fuel and efficiency multipliers (EV 1.6× more energy-efficient than a hydrogen vehicle; ~3× the renewable energy per hydrogen truck). These reinforce the I01 posture that a self-sufficient community should electrify directly and reserve hydrogen for the seasonal/off-grid residual.
Thesis angle (context: both). As the technical backing for OT_122, these volumes are the well-documented NZ primary for the strategic argument that direct electrification, not hydrogen, is the default decarbonisation route — with the Leeds H21 town-conversion case as a concrete, costed illustration of what full-scale hydrogen conversion actually entails (750k/MW of production plus 60M/yr O&M for a single UK city gate).
Research targets
Documents to retrieve
- (No new RT.) This ingest completes the RT_166 document set — Report 1 (Summary) = OT_122, Report 2 (Analysis) + Report 3 (Background) = this page. The three-report Concept Consulting (2019) study is now fully held.
Research gaps
- (No new RT.) An updated post-2019 NZ green-hydrogen production LCOE (against current electrolyser and electricity prices) would recalibrate the 2019
8.91/kg and12.56/kg off-grid benchmarks, but this recalibration is already carried by LIT_033’s existing research-gap residual and partly served by the 2024-era framing in CR_040 / OT_081. No separate RT raised.
Resolved / advanced
- RT_166 — RESOLVED (residual leg now closed → this page). RT_166 sought the Concept Consulting (2019) hydrogen study behind the “8.91–14 NZD/kg-H₂” benchmark LIT_033 attributes to it. OT_122 (Report 1 – Summary) verified the
8.91/kg** figure and the full current use-case matrix (6.80–12.56/kg) but left the row **OPEN** on the **"14 NZD/kg (small-scale)"** leg, noting the 14 figure was absent from the Summary and "likely lives in Report 2 (Analysis)." Report 2 (Analysis) has now been retrieved and read in full: its complete-model use-case matrix (Table 3) reproduces Report 1's exactly — highest current value **off-grid bulk storage12.56/kg — and no14/kg green-hydrogen production cost appears anywhere in Report 2 or Report 3.** The only "14" figures are SMR+CCS production at ~**14/GJ (per GJ, not per kg) and a plotted third-party comparison point (ENEA, ~15/kg, not a Concept estimate). **Finding: the "14 NZD/kg (small-scale)" attribution in LIT_033 is not substantiated by the Concept primary** — most likely a rounding/mis-read of the off-grid12.56/kg (or service-station $11.30/kg) row, or of a plotted comparator. RT_166 is therefore moved to Done → this source, with the “14” figure flagged as unverified against the primary. Do NOT enter “14 NZD/kg” into any NI cell citing this study.
Notes
Grey-literature consultancy reports (Concept Consulting Group Ltd, Wellington), Hydrogen in New Zealand — Report 2: Analysis (86 pp) and Report 3: Background Research (53 pp), both Version 04, saved 29-Jan-2019; sponsored by Contact, Meridian, Powerco, First Gas, MBIE and EECA, but stated to represent Concept’s own analysis and views. source_type: other (ot_ prefix), stored as a multi-file source in the subfolder source-files/07_other/ot_151_concept-2019-hydrogen-nz-r23/.
⚠ Not a duplicate of OT_122 — the completing technical volumes. OT_122 is Report 1 (the ~20-page Summary). This page is Reports 2 + 3, the full-analysis and background volumes. Report 2 adds the auditable cost model (input assumptions + per-component decomposition + sensitivity/optimisation analysis + SMR+CCS breakevens); Report 3 adds the hydrogen-technology reference (storage routes and costs, distribution, CCS, ammonia, the Leeds H21 case). None of this per-component/per-technology detail is in the Summary.
⚠ RT_166 “14 NZD/kg” — definitively not in the Concept primary. Reading Report 2’s complete cost model confirms what OT_122 could only suspect: the highest current green-hydrogen production cost in the full model is off-grid bulk storage 12.56/kg** (Table 3), and no 14/kg green-hydrogen production figure appears in either volume. The “14” values present are: SMR+CCS production ~14/GJ** excl. carbon (Report 2, Fig 20 — a per-GJ figure, and for hydrocarbon hydrogen not green), and a plotted **ENEA** comparison point at ~15/kg-H₂ in Report 2’s Figure 6 (a third-party estimate, not Concept’s). LIT_033’s “8.91 (large-scale) and 14 (small-scale) NZD/kg” is therefore an attribution error — the 8.91 is verified; the 14 is not a Concept production figure.
⚠ The “2.7/kg = 19/GJ” figure is NOT SMR (edit 2026-07-20). Concept’s modelled hydrocarbon (SMR+CCS) production cost is **~14/GJ** (≈ 2/kg), verified from Report 2 Figure 20 (“our estimate of approx. 14/GJ excluding carbon costs and with CCS"). The **2.7/kg = 19/GJ** value that an earlier framing attached to the SMR line is **not** an SMR estimate — it corresponds to a **green-hydrogen** production figure (≈ the Table 3 future-opportunistic Gas-Tx-injection value of 2.67/kg ≈ 19/GJ on HHV). Do not cite 2.7/kg / $19/GJ as an SMR cost in any NI cell.
⚠ Currency = NZD (confident). Same NZ firm, same six NZ Govt/utility sponsors, same NZ benchmarks (wholesale gas 6/GJ, electricity 0.075/kWh) as Report 1 — every ”$” is NZD.
⚠ Verified from rendered tables + layout text. The core cost tables (Report 2 Table 1, Table 2, Table 3, Table 4) and cost figures are embedded raster images; Table 1 and Table 3 were rendered at 130 dpi and transcribed cell-by-cell, Table 4 read from the rendered image, and every other cited figure read from the pdftotext -layout text — so data_quality: verified. The many qualitative figures (loss diagrams, TCO charts) are not cited as numeric claims.
⚠ Vintage 2019. Treat all cost figures as a 2019 NZ reference point; electrolyser capex and NZ electricity/carbon prices have moved since. Pair with the 2024-era framing in CR_040 / CR_042 / OT_081 (recalibration carried by LIT_033’s existing research-gap residual — no new RT).
Corpus fit. The technical backing for the D01 hydrogen evidence cluster — OT_122 (Report 1 Summary, the direct companion), LIT_033 (off-grid Rakiura MECM, 6.97 NZD/kg, and the source of the “14” attribution this page resolves), LIT_061 (seasonal H₂ storage), CR_040 / CR_042 (NZ community-H₂ viability & policy framing), OT_081 (MBIE Hydrogen Action Plan 2024), URL_016 (EU REMOTE off-grid H₂).
Connections
Links to
Referenced by
EDT domains (1): D01: Renewable Energy & Storage Systems
SSI indicators (1): I01: Financial & Economic Self-Sufficiency
Technologies (1): Hydrogen Storage (community-scale, seasonal)