Methodology & sources

How the Green Hydrogen Cost Atlas turns a click on the map into a levelized cost of hydrogen (LCOH), and where every number comes from.

What this is — and isn't. This tool is a global pre-feasibility screening model. It uses long-term satellite/reanalysis climatology, generic technology curves and transparent cost assumptions to compare locations and to show which cost components dominate. It is not a substitute for on-site resource measurement, hourly simulation, or project-specific engineering. Treat absolute values as ±25–30% and relative comparisons between sites as considerably better than that.

1. Plant architecture modeled

An off-grid, dedicated ("islanded") plant: a solar PV park or a wind farm whose only customer is a co-located electrolyzer. There is no grid connection, no battery, and no sale of surplus power — energy above the electrolyzer's rating is curtailed. This is the canonical configuration for large export-scale green hydrogen studies (IEA, IRENA, HyChain analyses).

Onshore points compare solar PV + electrolysis vs. onshore wind + electrolysis.
Offshore points model an offshore wind farm exporting power by submarine cable to an electrolyzer at the nearest shore. Cable length = great-circle shortest distance to the coastline; foundation type (fixed-bottom vs floating) follows the actual water depth at the point. Floating solar is not modeled.
Hydrogen is delivered compressed to 200 bar into a small buffer store at the plant gate. Downstream transport (pipeline, ammonia, shipping) is out of scope.

2. Input data

Dataset	Used for	Notes
NASA POWER climatology (2001–2020)	Solar irradiance (GHI), wind speed at 50 m, air temperature	Satellite (CERES/SYN1deg) + MERRA-2 reanalysis on a 0.5°×0.625° grid; valid over land and ocean. Fetched live per clicked point; monthly and annual means.
Natural Earth 50 m land polygons	Onshore/offshore classification; shortest distance to shore	Bundled with the app; distance computed to the nearest coastline segment (local equirectangular approximation).
ETOPO1 via OpenTopoData	Water depth at offshore points → fixed-bottom vs floating	1-arc-minute global relief. If the service is unreachable the app falls back to a distance-to-shore heuristic and says so.

A 20-year climatology smooths out interannual variability (±5% on wind CF, ±3% on solar, year to year) but cannot capture microscale effects — ridgeline speed-ups, coastal thermal winds, or horizon shading. Wind capacity factors derived from a mean speed and an assumed Weibull distribution are the largest single uncertainty in this model.

3. Solar PV energy model

Annual plane-of-array irradiance is estimated from horizontal irradiance (GHI) with a transposition factor for the mounting system, plus a bifacial gain:

GTI = GHI × transposition (1.22 tracker / 1.10 fixed) × (1 + bifacial gain)

Energy yield applies system losses and a temperature derate computed from the site's actual air temperature (generation-weighted cell temperature ≈ annual mean ambient + 3 °C daytime bias + 25 °C irradiance rise):

Yield [kWh/kWp·yr] = GTI × 365 × (1 − system losses) × (1 − γ·(T_cell − 25°C)) CF = Yield / 8760

Lifetime degradation (default 0.5%/yr) enters as a discounted average energy factor. Inverter clipping (DC/AC ratio) is not modeled separately — it is inside the system-loss term. The output duration curve used for electrolyzer coupling is a calibrated parametric curve g(x) = 1 − (x/x₀)ᵖ, x₀ = 0.45 whose mean equals the computed CF — i.e. generation occurs in ~45% of hours (daylight), peaking at rated power.

4. Wind energy model

NASA POWER's 50 m wind speed is extrapolated to hub height with the power law v(h) = v₅₀·(h/50)^α (α = 0.14 onshore, 0.11 offshore). Speeds are assumed Weibull-distributed with shape k (2.0 onshore — the Rayleigh assumption standard when only the mean is known — 2.2 offshore) and scale c = v̄/Γ(1+1/k).

The speed distribution is pushed through a generic turbine power curve parameterized by specific power (W of rated capacity per m² of rotor): cut-in 3 m/s, cut-out 25 m/s, rated speed from P/A = ½·ρ·Cp_eff·v³ with Cp_eff = 0.42, cubic power rise between. Wake, electrical and availability losses (default 13% onshore / 12% offshore) scale the result. Sampling 400 Weibull quantiles yields both the capacity factor and the exact output duration curve.

5. Electrolyzer coupling — the sizing ratio

The central design decision of an islanded hydrogen plant is the sizing ratio r — generator capacity per unit of electrolyzer capacity. Oversizing (r > 1) fills the electrolyzer's duty cycle (more kg per $ of electrolyzer) but curtails generation peaks (fewer kWh per $ of generator). From the generation duration curve g(x):

electrolyzer load(x) = min( r · g(x) · (1 − cable loss), 1 ), zero below minimum load electrolyzer CF = ∫₀¹ load(x) dx curtailed share = 1 − CF_ely / (r · CF_gen)

Defaults are r = 1.6 for solar and 1.15 for wind; the ⚙ Optimize button sweeps r from 0.6 to 3.0 and adopts the LCOH-minimizing value for the clicked site. Minimum-load cutoffs (5% PEM, 15% alkaline) shut the plant down in low-resource hours. Because the model works on annual duration curves, short-term dynamics (ramping, cold starts, day/night cycling wear) are not explicitly simulated.

6. Financial method

All costs are annualized with the capital recovery factor at a single real WACC (default 7%):

CRF(w, N) = w·(1+w)ᴺ / ((1+w)ᴺ − 1) LCOH = Σ annualized costs [$/kW_ely·yr] ÷ hydrogen output [kg/kW_ely·yr]

Component lifetimes differ: generation assets over their own life (30 yr PV / 25 yr wind), transmission over 30 yr, electrolyzer and compression over the 25-yr project.
Interest during construction: CAPEX × (1 + WACC × build-years ÷ 2).
Contingency (default 5%) applies to every direct CAPEX line.
Stack replacement is scheduled from the stack-hour budget divided by the site's actual operating hours per year, costed as the stack line + 10% labour, discounted to present value and annualized. A solar-driven electrolyzer (~4,000 op-h/yr) replaces a 65,000-h PEM stack once in 25 years; a high-CF offshore-wind plant replaces it twice.
Water is charged per kg (10 L demineralized × 1.35 raw-water factor × $/m³); demin equipment CAPEX sits inside the electrolyzer balance-of-plant line.
Compression & storage (optional, on by default): 30→200 bar compression energy is drawn from the same renewable supply (raising kWh/kg); compressor sized to peak H₂ flow, buffer store sized in hours of average production.

7. Offshore transmission

For offshore points the export system is sized to the electrolyzer intake (excess wind output is curtailed at the platform, so the cable never needs to carry the full oversized farm rating). The model prices both options at the site's cable distance and picks the cheaper:

HVAC: $240/kW substations + $4.5/kW·km losses 0.5% + 0.03%/km HVDC: $430/kW converter pair + $1.8/kW·km losses 1.4% + 0.0035%/km

The crossover lands near 70–90 km, matching industry practice. Cable losses reduce delivered energy. Foundations: fixed-bottom to 60 m depth (ETOPO1), floating beyond — floating adds platform/mooring CAPEX, extra installation cost and higher O&M. The cable route is drawn as a straight line to the nearest shore point; real routing, seabed conditions and landfall constraints are site-specific.

8. Every default, with its source

The tables below are generated from the same file the model reads (assumptions.js) — the documentation cannot drift from the calculation. All values are editable in the app's Assumptions tab. Costs in 2024 US$; rates are real.

9. Known limitations

Statistical (duration-curve) coupling, not hourly simulation: no storage arbitrage, no solar+wind hybrids, no battery smoothing. Hybrid plants can beat both single-source options.
Weibull-from-mean wind estimation; no terrain speed-up or roughness modeling.
No land-use, protected-area, water-availability or grid-proximity screening — a cheap cell in the Sahara still needs a port and water; the water cost is included, its availability is not.
Single global WACC unless you change it — in reality financing costs vary by country more than technology costs do.
Offshore: straight-line cable route; electrolyzer assumed onshore (in-turbine or platform electrolysis with H₂ pipelines to shore is an emerging alternative not modeled).
No hydrogen delivery beyond the plant gate, no conversion to ammonia/derivatives.

10. References

IRENA, Renewable Power Generation Costs in 2023 (2024) — installed cost, O&M and LCOE benchmarks for solar PV, onshore and offshore wind.
NREL, Annual Technology Baseline 2024 — bottom-up CAPEX breakdowns, O&M, lifetimes and financial assumptions.
IEA, Global Hydrogen Review 2024 — electrolyzer system costs, efficiencies and deployment status.
US DOE Hydrogen & Fuel Cell Technologies Office — H2A production records and technical targets (electrolyzer CAPEX shares, stack life, compression energy and costs).
Danish Energy Agency, Technology Data catalogues — generation and renewable-fuel plant cost/performance data.
NREL offshore wind cost studies and ORE Catapult guides — offshore CAPEX splits, export-system (HVAC/HVDC) costs and the AC/DC distance crossover.
Lazard, LCOE+ (June 2024) — cross-checks on LCOE and hydrogen cost ranges.
NASA POWER, API documentation; Jordan & Kurtz (NREL), Photovoltaic Degradation Rates; IEA Wind Task 37 15 MW reference turbine.

← Back to the map