New Solar PV Rules a bonus for business
New rules reduce the cost of large
scale solar.
Allows cheaper expansion of existing arrays and new installs.
The 5 August 2026 announcement to lift the SRES/STC solar-PV ceiling from 100 kW to 1 MW is a substantial change to the economics of commercial solar, particularly because it changes when the subsidy is monetised
The important distinction is that it doesn't merely make 101 kW–1 MW projects eligible for another certificate scheme. Those projects could already use the Large-scale Renewable Energy Target in many cases. The change effectively converts much of the support from a future operating revenue stream (LGCs) into an upfront capital contribution (STCs).
Old model vs new model
Currently, solar PV up to 100 kW can create STCs. Above 100 kW, a project generally moves into the large-scale power-station/LGC regime.
Under the announced change, new installations and expansions up to 1 MW will be able to receive upfront deemed STCs, with commencement expected from 1 October 2026, subject to the regulations being made. The announced arrangements also contemplate a five-year deeming period through 31 December 2030 for these larger systems.
| Certificate | LGC | STC |
| Benefit received | As electricity is actually generated | Deemed upfront |
| Cash timing | Years into future | At installation |
| Production risk | Owner/financier carries it | Much less relevant to certificate value |
| Certificate-price risk | Ongoing | Largely crystallised upfront |
| Administration | Power-station/LGC regime | Simpler SRES pathway |
| Effect on project capex | Limited | Material upfront reduction |
| Financing requirement | Finance gross capex, then receive LGC income | Finance net capex after STC value |
That last point is probably the most important one from a funding perspective.
What happens to the funding requirement
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Suppose, illustratively, an 850 kW commercial rooftop project costs $900,000 installed.
Under the previous model, the customer/financier essentially has to find the ~$900k upfront. The project then earns LGCs over time from actual generation, which contributes to its investment return.
Under the announced STC model, government estimates reported for an 850 kW installation indicate an upfront benefit of about $230,000. A 250 kW system is estimated at roughly $68,000. Overall, the government expects the change to reduce C&I solar installation costs by around 20%.
So the financing picture becomes roughly:
$900k project cost − $230k STC value = ~$670k net capital requirement.
That's fundamentally different from saying:
$900k capital requirement + an LGC revenue stream over subsequent years.
For a financier, ESCO, PPA provider or equipment-finance structure, that's quite powerful.
Why STCs are more valuable for financing than equivalent future LGC income
Even if the nominal certificate value over the life of the two alternatives were similar, $1 of STC subsidy received on day one is financially more useful than $1 of LGC revenue received progressively over several years. It reduces:
- debt/equity required at financial close;
- customer contribution;
- interest expense;
- exposure to future certificate prices;
- exposure to generation underperformance;
- working capital;
- payback period.
And because less capital has to be financed, it can improve DSCR and project IRR disproportionately to the nominal value of the STCs. For an equipment-finance model, you could effectively finance the post-STC contract price rather than the gross system price.
There's another significant change
Under the normal residential/small-commercial STC scheme, the deeming period has been progressively declining as 2030 approaches. Current STCs are based on estimated generation remaining to the end of the scheme.
The announced arrangement for the 100 kW–1 MW category is different: reporting on the announcement says these systems are expected to retain a five-year deeming period through to 31 December 2030 rather than having that period reduce every year.
That's important.
For example, very approximately, if a 500 kW Sydney commercial system generated around 700 MWh/year, five years of deemed production represents around:
700 MWh × 5 years ≈ 3,500 STCs.
At an illustrative realised STC value of, say, $38/STC, that's: 3,500 × $38 ≈ $133,000 upfront and that's about $266/kW of capital subsidy.
The exact entitlement will depend on the final regulations, location/zone, system configuration and applicable calculation rules, so I wouldn't use that example as a quotation yet.
Who actually funds the STCs?
This is also quite different from the battery STC program. For ordinary solar PV, the SRES isn't normally a direct Commonwealth budget grant. STCs are tradeable certificates and electricity retailers/other liable entities are required to acquire and surrender them under their SRES obligations. PV Tech reports that the government expects this expansion to remain budget-neutral to government because it operates through that existing market mechanism.
That's different from the Cheaper Home Batteries Program, where the Commonwealth specifically purchases an equivalent quantity of battery-created STCs so the additional liability isn't passed through to electricity consumers.
So economically:
Commercial solar STC expansion
Electricity-market SRES liability → STC purchaser → installer/project → upfront reduction in solar capex
rather than:
Project investor → funds 100% of capex → generates electricity → creates LGCs → sells LGCs → recovers subsidy progressively
The really interesting commercial consequence
This could substantially change the viable market between about 150 kW and 1 MW.
That segment has always had a financing problem: projects are too large to get the simple residential-style STC discount, but often too small for sophisticated project finance/PPA structures to be economical. That's precisely the "missing middle" the government says it is targeting.
For a 300–900 kW warehouse, factory, shopping centre, farm, cold-storage facility or similar business, you could potentially structure:
Gross solar EPC cost
− upfront STCs
= financed amount
÷ 5–10 year equipment-finance term
The customer's monthly finance payment can then be compared directly against avoided grid electricity expenditure. That can turn projects which previously required a significant upfront contribution or a 7–10 year investment case into something much closer to cash-flow-positive-from-day-one energy infrastructure.
One caveat: as of 8 August 2026, the CER describes the 1 MW expansion as announced “subject to regulations being made”, so the final regulations need to be checked before treating these mechanics as settled.
