Every scenario is modelled hour-by-hour: 8,760 hours of your load data are run against local TMY weather for the site, a PVWatts-style production model, a battery dispatch simulation, and your actual tariff. Figures are indicative estimates — not a quote — and may change once verified.
Every figure in Amperage — payback, NPV, year-one savings, self-sufficiency — comes from the same pipeline: real consumption data, local weather, a physical production model, and a lifetime cashflow model. No rules of thumb, no “typical household” multipliers. Here is each stage.
Weather: typical-year data for the actual site
Production is driven by TMY (Typical Meteorological Year) data — hourly irradiance and temperature assembled from long-term measurements to represent a typical year, not an unusually good or bad one. Amperage matches the project’s location to the closest available TMY dataset, so a Cairns roof and a Hobart roof are modelled on their own weather, not a national average.
Production: a PVWatts-style hourly model
For each of the year’s 8,760 hours, the model converts irradiance on the panel plane into AC output the way the industry-standard PVWatts approach does — accounting for panel orientation and tilt, temperature effects on efficiency, and system losses (soiling, wiring, inverter efficiency). Long-term panel degradation is applied across the analysis life, so year 20 is not credited with year 1 output.
Consumption: your 8,760 hours, not a profile template
The interval data uploaded in the Consumption stage is cleaned and aligned with the weather year, giving the model the site’s real load for every hour. That hourly alignment is the whole game: two sites with identical annual kWh but different shapes get very different systems, because what matters is how much generation lands on load (self-sufficiency) versus being exported at a low feed-in rate.
Batteries: simulated dispatch, not nameplate maths
Battery scenarios run an hourly dispatch simulation: charge from surplus solar, discharge to cover evening load, within the battery’s capacity and power limits and round-trip efficiency. That is why a battery that looks big on paper can add little value on a daytime-heavy site — the simulation shows there is nothing left to store or nothing to discharge into.
Tariffs and incentives: valued the way the bill is billed
Savings are valued against the project’s actual tariff — time-of-use windows, demand charges, daily charges, and the feed-in rate — so a kilowatt-hour offset at peak is worth more than one at off-peak. Eligible incentives (STCs, LGCs, VEECs, PDRS) are applied by state, postcode zone and system size: upfront ones reduce net cost, and annual LGC revenue enters the cashflow as a time-limited stream through 2030.
The financial model
- Year-by-year cashflows over the analysis life, with electricity price escalation and panel degradation applied.
- Payback, NPV and IRR are all computed from that one cashflow series — one basis for every system size, so squares in the sizing matrix are genuinely comparable.
- The assumptions are yours to change: discount rate, escalation, analysis years and optional depreciation live in the scenario settings, and every number on the page updates when you change them.