Labor is removing the 100 kW incentive cliff. For solar installers, that opens a major new market - but it also raises the bar.
Energy Minister Chris Bowen has announced that the Small-scale Renewable Energy Scheme will be expanded from 100 kW to 1 MW, cutting the upfront cost of eligible commercial, industrial and agricultural solar by around 20 per cent. The government’s worked examples put that at roughly $68,000 off a 250 kW system, $136,000 off 500 kW and about $270,000 on a 1 MW installation. Commencement is expected from 1 October 2026, subject to the necessary regulations being in place.
For years, 100 kW has been a dividing line in Australian solar. Below it, projects qualified for an upfront STC benefit: a familiar sales process, a manageable design pathway and an incentive the customer could see reducing the purchase price. Once a system crossed 100 kW, the rules changed. The project entered the large-scale certificate system, administration increased, certificate value was earned progressively rather than received upfront, and grid connection tended to become more complex.
The result was predictable. Many projects stopped at 99.9 kW, even when the customer had the roof space, the electricity use and the financial case for a much larger system.
This is a major change, but it is not simply a larger rebate. It is an invitation for solar companies to enter a more valuable and more demanding part of the energy market. Installers that respond well could expand rapidly. Those that approach a 500 kW project as though it were five 100 kW systems joined together may find themselves exposed technically, financially and contractually.
A reality check on the 20 per cent
Before anyone starts quoting a flat discount, it is worth knowing what the published figures describe.
Certificate value is capacity multiplied by the zone rating for the site’s postcode, multiplied by the deeming period, multiplied by the certificate price. The government’s examples reconcile exactly on a Zone 3 site – Sydney, Brisbane, Adelaide, Perth – at the 2026 deeming period of five years and a market certificate price near $39. The numbers are accurate.
Two things move them. The first is location: the same 500 kW system is worth roughly $134,700 in Zone 3, about $115,500 in Melbourne or Hobart, and about $158,100 in the Northern Territory. The published figure is not the figure a Victorian customer will see.
The second is the calendar. The SRES is legislated to end on 31 December 2030, and deeming steps down by one year every 1 January. A system installed in 2026 earns five years; one installed on 2 January 2027 earns four. With commencement on 1 October, that leaves about 90 days at the current rate – and a 500 kW project realistically takes four to nine months from first enquiry to commissioning, longer if the network connection is contested. Until the regulations are made, few customers will sign against an incentive that does not yet legally exist.
So the first substantial wave of projects will most likely be contracted late in 2026 and delivered through 2027, one deeming year lower. That is about $27,000 on a 500 kW system and $54,000 on a 1 MW system. Industry commentary suggests the expanded class may retain a fixed five-year rate through to 2030 rather than stepping down, which would remove the problem entirely – but that is not confirmed, and until it is, contracts should say who wears the difference if commissioning slips past New Year’s Eve.
None of this undermines the reform. It does mean the number in a proposal should be a certificate count and a stated price, not a percentage borrowed from a media release.
Why the government has made this move
Australia has been extraordinarily successful at putting solar on homes. Commercial and industrial rooftops tell a different story. According to figures from the Institute for Energy Economics and Financial Analysis quoted by the minister, residential rooftop solar sits at around 22 GW while businesses have installed only about 5.6 GW – most of that below 100 kW. This is despite businesses consuming more electricity and using much of it during daylight hours, when onsite generation is most useful.
Warehouses, factories, shopping centres, farms, schools and commercial buildings frequently have large roof areas sitting above substantial daytime loads. Yet many remain empty, or carry systems sized around the former incentive threshold rather than the actual energy opportunity.
This is the commercial and industrial “missing middle”. It sits between two markets that have received much stronger support. Household solar has benefited from a simple incentive structure, a mature installation industry and a straightforward customer proposition. Large renewable projects have attracted institutional capital and dedicated government programs. Mid-sized commercial projects have been caught between the two – too large for the traditional small-scale pathway, too small to comfortably absorb the development costs and administrative complexity of utility-scale work.
A business considering 250 kW, 500 kW or 850 kW will now receive a larger and more certain upfront benefit, which helps the project compete with other calls on capital: machinery, vehicles, staffing, property upgrades or debt reduction. It also allows systems to be designed around the site rather than the scheme. A warehouse with the roof area and daytime demand for 400 kW should not be offered 99.9 kW simply because the certificate process is easier.
The policy logic is strong. Commercial solar uses existing buildings and supplies power close to where it is consumed, generally without new transmission lines, land acquisition or years of development approvals.
The government has also signalled movement on the second barrier. Bowen has said he will ask the Australian Energy Market Commission to require network service providers to approve commercial and industrial solar connections faster, citing delays that cause businesses to abandon projects altogether. That is welcome – but a rule change request is not a rule change, and any reform will arrive well after the first wave of projects. Connection risk remains the installer’s to manage.
An incentive can only make a project cheaper. It cannot ensure the system is well sized, the savings accurately modelled or the customer given a credible investment case. Those challenges fall to the industry.
The 100 kW ceiling was also a capability ceiling
Australian solar businesses have become highly effective at selling residential and small-commercial systems. They understand panels, inverters, warranties and installation, can review an electricity bill, explain self-consumption, provide an indicative payback and often close directly with the business owner.
That experience is a solid foundation, but it will not be enough for the next market.
A 500 kW or 1 MW system is not a larger product purchase. It is a substantial capital investment that must compete with other uses of money inside the business, and it will be assessed by people who assess capital investments for a living. The customer may have a chief financial officer, a board, an operations manager and a procurement process. There may also be a landlord, tenant, lender, energy consultant or external engineer involved.
Each will look at the project differently. The owner wants to know whether it will reduce costs. The CFO wants to know whether the return can be trusted. The operations manager wants to understand disruption and operational risk. The engineer wants confidence the system can connect and perform as designed. The lender wants to know what happens if the site load changes.
A proposal stating that the system will save $80,000 a year and achieve a four-year payback will no longer be sufficient. The customer will want to know where the $80,000 comes from – and they should.
The installer is selling investment confidence
The installer is still selling solar equipment, but the real product becomes confidence: that the system is correctly sized, that the tariff has been understood, that the generation forecast is reasonable, that network and installation risks have been considered, and that the lifetime return has not been inflated.
This changes the opening sales conversation. The first question should not be how many panels will fit on the roof. It should be what is happening inside the customer’s business.
When does the site operate, and when are its largest loads? Does it run on weekends? Is production expected to grow? Is refrigeration operating overnight? Are electric vehicles or electrified process loads likely to be added? Is the building owned or leased, and how long is left on the lease? How important is backup power? What rate of return does the business require before it approves a capital project?
Those answers shape the system. The equipment selection comes later.
Two sites can use the same total electricity each year and still need very different solutions. A weekday office, a seven-day supermarket, a refrigerated warehouse and a seasonal food processor may all have similar annual consumption, but their load shapes, demand peaks, solar utilisation and battery opportunities will be completely different.
A more commercially literate sales team
Salespeople do not need to become accountants or electrical engineers, but they do need to become commercially literate – able to explain where the value comes from, identify the assumptions that matter and recognise when specialist advice is required.
| The customer's question | Why it matters | What the solar team should explain |
|---|---|---|
| A headline payback can hide the real drivers of value. | Separate solar self-consumption, energy savings, demand reduction, export income and other benefits. | |
| How reliable is the result? | Larger projects receive greater financial scrutiny. | Show the source of the data, the major assumptions and conservative, expected and opportunity scenarios. |
| What happens if our business changes? | Loads may rise, fall or shift to different times. | Test production growth, changed operating hours, EV charging and other likely future loads. |
| Why is this the right system size? | The largest system is not always the best investment. | Explain the interaction between interval demand, roof area, exports, connection constraints and financial return. |
| What could affect the outcome? | Connection costs, curtailment, certificate timing and equipment replacement can change the result. | Identify key risks, allowances and the stages at which major decisions will be confirmed. |
| How will we know the system delivered? | Management may need to report results to a board, lender or owner. | Include monitoring, performance comparison and measurement of actual savings. |
This form of selling relies less on pressure and more on helping the customer reach a defensible decision. That should improve the quality of the industry, and it favours companies that can combine electrical and design capability with clear financial communication.
Larger projects expose weak assumptions
A rough assumption may not materially change the outcome of a 30 kW project. Apply the same error to a 1 MW system over 20 years and it can distort the forecast by hundreds of thousands of dollars.
A customer may use 2 GWh of electricity each year, but that number alone tells us very little about the right system. What matters is when the energy is used. One business may operate from 7 am to 5 pm on weekdays; another may have continuous refrigeration; a third may shut down for several weeks each year; a fourth may use most of its electricity during a short, intensive production period. Their annual consumption could be similar. Their solar outcomes will not be.
A credible assessment should normally begin with interval meter data covering at least 12 months. This reveals weekday and weekend patterns, seasonal changes, demand peaks and the relationship between site load and potential solar production. It also shows whether excess generation is likely to be occasional or structural – a distinction that matters when assessing exports, curtailment and storage.
The financial model then needs to bring together site load, solar production, tariff periods, network demand charges, export limits, equipment losses, degradation, maintenance, replacement costs, tariff changes, finance costs and future load growth.
The result should not be one impressive-looking number. It should be a clear and traceable investment story.
A payback period is not a complete business case
Simple payback remains useful because it is easy to understand. But it does not explain the value created after payback, reflect the timing of cashflows, properly compare a cash purchase with a financed project, or show whether the investment exceeds the business’s required rate of return.
Larger proposals should include a fuller set of measures: annual cashflow, internal rate of return, net present value, discounted payback and lifetime savings. The sales team does not need an academic understanding of every metric, but it does need to explain them in practical language.
“The simple payback is approximately five years. The project also produces a positive net present value at your required discount rate, and the return remains above your investment threshold under the conservative scenario.”
That is a far stronger statement than telling the customer that solar is a no-brainer. Financially literate customers rarely trust claims that sound too easy. They trust evidence, transparent assumptions and a clear explanation of risk.
Show the assumptions before presenting the answer
A financial model becomes more credible when the customer can see what drives it. What percentage of generation is expected to be consumed onsite? What export price has been used? Has electricity price escalation been assumed? Have degradation and equipment replacement been included? Are tax benefits embedded in the headline result? Does the model assume the site load will remain unchanged for 20 years?
There is no single correct forecast for the next two decades, and false precision is not the objective. The aim is a reasonable expected case, tested against a conservative case with lower price escalation, reduced load growth and higher operating costs, and an opportunity case including planned expansion, new EV charging loads or stronger tariff savings.
Showing a range does not weaken the sale. It demonstrates that the project has been tested. When the investment remains attractive under conservative assumptions, the salesperson has a much stronger argument.
The value is often stacked
The first layer of value is straightforward: solar generates electricity, the business consumes it onsite and buys less from the grid. Larger projects create more. Solar may reduce daytime demand. A battery may reduce the monthly demand peak. Energy can be shifted away from expensive tariff periods, or stored rather than exported at a low rate. EV charging can be moved into solar hours. Backup capability may reduce outage risk. The system may help satisfy emissions, tender or customer requirements.
Together these can produce a compelling case. They should not be combined into one unexplained annual savings figure. Separate the value by source and by confidence.
Core value is the most dependable layer: onsite solar consumption and clearly identifiable tariff savings supported by the customer’s existing load data.
Managed value depends on how the system is controlled and operated – demand reduction, battery load shifting, solar charging and managed EV charging.
Market value relies on external prices, programs or commercial counterparties: wholesale dispatch, battery exports, demand response and grid services. These can be material, but they belong in a different confidence band from direct onsite savings.
Strategic value may never appear on the electricity bill – resilience, carbon reduction, energy price certainty, improved property performance and capacity for future electrification. It still influences the decision.
Separating these makes the business case easier to understand and prevents uncertain future revenue from being presented as guaranteed savings. It also gives a CFO a way to discount the layers they do not believe without rejecting the project outright.
Batteries strengthen the opportunity - and complicate the analysis
The reform will create more battery opportunities. A larger solar system may produce surplus generation around midday. The customer may face high demand charges later in the afternoon, or want backup power, managed EV charging or exposure to variable prices.
But the incentive does not follow the solar. This expansion covers solar only. Battery support under the Cheaper Home Batteries Program remains capped at 100 kWh of nominal capacity, and that support is reviewed at least annually and declines toward 2030, having already stepped down in May 2026. A 600 kW array paired with a 400 kWh battery attracts certificates on the array alone. Battery value therefore has to be earned in the modelling rather than assumed from the headline.
A battery also cannot deliver every benefit at the same time. Energy reserved for backup is unavailable for daily load shifting. A battery discharged to avoid an evening energy charge may not have the capacity left to control a later demand peak. Grid charging during a low-price period can create a new demand peak if it is not coordinated with site load. Heavy market cycling increases degradation.
The financial model must therefore simulate an operating strategy rather than assume one profitable cycle a day. For one customer the priority order might be: maintain a minimum backup reserve, reduce site demand peaks, store excess solar, avoid high-priced grid energy, then use remaining capacity for market-responsive dispatch. Another may place resilience first and accept a lower return. A third may have no backup requirement at all.
The same stored kilowatt-hour cannot simultaneously receive credit for increased self-consumption, demand reduction, tariff arbitrage and export revenue. Avoiding that double count is essential to a defensible return.
Energy management becomes part of the investment
For larger solar and storage projects, the energy management system is not an optional accessory. The hardware creates the capability; the control system determines how that capability is used.
A capable platform can forecast solar production, anticipate site demand, maintain battery reserves, avoid demand peaks, coordinate EV charging and respond to changing prices. It also provides accountability: the customer should be able to see what the system did, why it charged or discharged, what value was created and whether actual performance matches the investment model. That closes the gap between the proposal and the operating asset, and for a financially sophisticated customer it is a major source of confidence.
Technical and delivery risk also increase
The incentive pathway may become simpler, but the project does not. Larger systems create greater requirements around network connection, switchboard capacity, protection, structural engineering, cable design, power quality, metering, access, shutdown planning and commissioning.
Connection is likely to remain one of the largest uncertainties regardless of what the AEMC eventually decides. Network assessment should not be left until the final stages of the sale; a preliminary assessment should occur before the investment case is locked in. Potential export restrictions should be understood, protection and switchboard requirements investigated, and unconfirmed costs clearly identified as allowances rather than hidden within a fixed headline price. Most customers accept some uncertainty. What damages confidence is discovering a major constraint after the project has been approved.
Commercial exposure rises too. Equipment deposits, procurement lead times, working capital, contractual performance obligations and project delays all become more significant. So does certificate exposure: a large increase in eligible capacity is a supply-side event in the STC market, and an installer who pre-sells certificates at an assumed price is carrying a risk on a 1 MW job that never existed on a 10 kW one. The company’s financial and project management systems must mature alongside the size of the installations it delivers.
Do not move directly from 99 kW to 1 MW
The new market should be approached progressively. A company experienced in 50–100 kW systems may focus first on 100–250 kW, introducing larger designs, more detailed investment discussions and more demanding connection work without immediately taking on the full risk of a 1 MW project. The next step may be 250–500 kW, then 500 kW–1 MW once engineering, financial and delivery capability is in place.
The progression is not only about system size. At each stage the business must strengthen customer qualification, interval data analysis, tariff modelling, network assessment, financial modelling, contracts, procurement, working capital and performance reporting.
Specialist partners can fill some of these gaps. A solar business does not need to employ a network engineer, structural engineer, accountant, energy trader and finance specialist from the beginning. It does need to recognise when each capability is required and bring those inputs together into one clear customer solution.
There is, however, a clock. The scheme is legislated to end on 31 December 2030 – roughly four years from commencement. The staircase has a deadline, and a business planning to spend two years reaching 250 kW competence will arrive as certificate value is thinning. Progression should be deliberate, but it cannot be leisurely.
Training must extend beyond installation skills
The industry already invests heavily in electrical safety, technical accreditation and product training. The move to 1 MW creates another requirement. Salespeople need to understand commercial tariffs, capital investment and financial metrics. Designers need to understand how design decisions affect lifetime return. Electricians and project managers need to understand the operational conditions and commitments built into the sale.
The whole team needs a shared understanding of the business case. A salesperson should not promise demand-charge savings that have not been modelled. A designer should understand why a customer may prefer a smaller system with a stronger return. A project manager should know which shutdown constraints were agreed during the sale. A commissioning technician should understand the control strategy assumed in the financial model.
When these functions operate separately, the proposal and the final system drift apart. When they are aligned, the customer receives what was sold.
The real opportunity is not simply selling more panels
The expanded scheme will generate new enquiries and make larger systems easier to justify. It will also attract more solar companies into the commercial market. Competition will increase, quoting will become faster, and marketing claims will become louder.
The best opportunity is not to sell more capacity. It is to become the company that can explain a complex energy investment clearly and support the customer through the full decision.
The strongest businesses will demonstrate why the system is correctly sized, how it interacts with the customer’s load, where the financial value comes from, which assumptions matter and how the project responds to future change. They will explain how network and operational risks have been addressed, how storage or EV charging may be added later, and how actual performance will be measured after installation.
That is a more valuable service than quoting panels by the kilowatt. It is also much harder to commoditise.
A new market demands a new level of rigour
The government has removed a major policy barrier. The 100 kW cliff encouraged undersized projects and split the commercial market into two very different pathways. Extending the small-scale framework to 1 MW should help unlock factories, warehouses, farms, retail buildings, schools, hospitals and other large energy users.
The rebate is only the beginning. Solar companies must now sell larger investments to more demanding customers, with stronger energy analysis, more transparent lifetime modelling and a better grasp of tariffs, demand charges, batteries, finance and connection risk – and they must make that complexity easy for the customer to understand.
The 100 kW threshold shaped the systems this industry sold. Its removal should also mark the end of 100 kW thinking. The next stage of commercial solar will not be won by the company with the lowest cost per watt or the fastest quotation. It will be won by the company that can turn energy complexity into investment confidence.