Assumptions & Sources
Every cost figure on this site is one of three things: an external fact with a source, a TASC estimate whose assumptions are on this page, or a labelled scenario. This page holds the estimates. If an input is wrong, say so — the contact form has a category for exactly this.
Inputs
| Input | Value | Class | Basis |
|---|---|---|---|
| Solar capex per MW, at scale | A$0.9–1.2M/MW | A — external | GenCost 2025-26 large-scale PV[1] |
| Capacity factor, inland | 22–24% | A — external | Global Solar Atlas[2] |
| LFP BESS installed cost, 2028–30 | A$300–400/kWh | A — external | GenCost storage capex tables[1], cross-checked against Lazard LCOE+[3] |
| WACC, institutional infrastructure | 6–8% | B — TASC assumption | Blended debt/equity rate assumed for institutional infra at this risk grade. |
| Project life | 25 years | B — TASC assumption | Standard utility-scale PV assumption; drives the amortisation in the ladder. |
| Availability target | 99% | C — design choice | The reliability the corridor is designed to sell. Raising it raises storage sizing sharply. |
| Storage-to-generation ratio | 6–10 GWh per GW | B — TASC model | Driven by winter trough dispatch rather than annual energy balance — the upper end is the winter case. |
| Solar density | 40–55 MW/km² | A — external | Single-axis tracking layouts[2] |
| Transmission adder | A$10–30/MWh | A — external | AEMO Transmission Cost Database / 2026 ISP inputs[4] |
Why this sits below GenCost
A reader who knows GenCost will ask why this site’s firmed figure (A$80–120/MWh) sits below CSIRO’s published cost of firmed renewables at high VRE share (A$141–152/MWh in GenCost 2025-26). The two numbers measure different systems. GenCost’s figure is grid-scope: it includes transmission builds, system-integration costs, and the obligation to serve every load shape on the network. The corridor’s figure is a bespoke off-grid node: co-located generation and load, no transmission component, one contracted load shape, sized storage. That is precisely the design argument — co-location removes the cost layers that make grid-delivered firmed power expensive. If the corridor’s number were above GenCost’s, the concept would be dead. Whether A$80–120 is achievable is exactly what Gate 1 exists to prove, and the model below is open so the estimate can be challenged now.
Coastal comparator, decomposed
| Component | Value | Class | Basis |
|---|---|---|---|
| ASX Energy Cal-28/29 baseload band | A$85–115/MWh | A — external | Forward curve as at Aug 2026[5] |
| Firming premium to 99% availability | A$30–50/MWh | B — TASC estimate | Cost of contracting round-the-clock cover against a merchant baseload position. |
| Network and retail components | A$15–25/MWh | B — TASC estimate | Delivered-to-site network charges and retail margin at data-centre scale. |
| Delivered firm, coastal | A$130–190/MWh | B — TASC estimate | The comparator the corridor is priced against. |
The model
Sources
- CSIRO, GenCost 2025-26 Final Report, 2026-07. link Accessed 2026-08. Large-scale PV LCOE ranges; storage capex tables B.4–B.6; system-level firmed renewables $141–152/MWh (grid scope, incl. transmission & integration).
- World Bank / Solargis, Global Solar Atlas, 2026. link Accessed 2026-08.
- Lazard, LCOE+ (levelized cost of energy analysis), 2025. link Accessed 2026-08.
- AEMO, Transmission Cost Database / 2026 ISP inputs, 2026. link Accessed 2026-08.
- ASX Energy, Australian electricity baseload futures (Cal-28/Cal-29), 2026-08. link Accessed 2026-08. Volatile — refresh the accessed date whenever the forward-curve claim is re-verified.