Several structural forces are aligning that rarely converge: commercially mature technology, retail electricity tariffs that remain significantly above pre-2021 levels despite recent wholesale price moderation, a maturing incentive landscape, and reporting obligations that now require the digital infrastructure many organisations have been deferring. For commercial and industrial decision-makers, 2025 to 2026 is not simply a favourable window — it is a sequencing decision with material financial and regulatory consequences.

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WHY THIS PERIOD IS DIFFERENT

Technology that is proven and well-supported

Solar photovoltaic systems and behind-the-meter batteries have moved well past early-adopter risk. Installation pipelines are mature, performance data is robust, and integration with building and energy management systems is routine. The Australian Renewable Energy Agency continues to support distributed energy, digital control, and demand flexibility. Organisations deploying these technologies today are executing against established benchmarks, not managing technology risk.

Retail tariffs that still justify the investment — despite falling wholesale prices

NEM wholesale prices have fallen significantly — down 27% year-on-year in Q3 2025 — as renewables capacity has grown. However, retail tariffs for commercial customers remain structurally elevated: in New South Wales, flat commercial rates run from 23 to 33 cents per kilowatt-hour, reflecting network, environmental, and retailer cost layers that do not fall with wholesale prices in the short term. Organisations with onsite generation and storage can hedge against this cost structure, reduce peak demand charges, and achieve operating cost predictability that grid-dependent competitors cannot match.

The AEMC is also finalising a major pricing review — final report expected June 2026 — proposing to shift more network costs into fixed charges and enable more flexible tariff products. Organisations that invest in digital metering and energy management infrastructure now will be better positioned to navigate these changes as they take effect from late 2026.

Reporting obligations that are now law — not just expectation

The Australian Sustainability Reporting Standards are mandatory law under the Corporations Act 2001, with penalties of up to $15 million or 10% of annual turnover for false or misleading disclosures. Group 1 entities are reporting now, for financial years beginning on or after 1 January 2025. Group 2 entities begin reporting for financial years commencing 1 July 2026 — meaning their first mandatory reporting period starts this year.

There is a three-year limited liability window for Scope 3 emissions, scenario analysis, and transition plans, during which only ASIC — not private litigants — can bring action. This is not a reason to defer. It is precisely the window in which to build the data infrastructure and verified baselines that will be required when full liability attaches in 2027. The same infrastructure that optimises energy operations provides the audit-ready data trails ASRS compliance demands.

Flexibility markets that are opening — but not fully open yet

The AEMC finalised its determination in December 2024 that virtual power plants, commercial and industrial demand response, and aggregated batteries will compete directly with traditional generators in the NEM wholesale market from May 2027. A $50 million incentive programme to support participation is available from April 2026. Most commercial sites investing in batteries and controls in 2025 and 2026 will primarily derive value from behind-the-meter savings and demand management, with flexibility revenue as a growing supplementary opportunity from 2026 onward.

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TECHNOLOGY PRIORITIES FOR COMMERCIAL SITES

The sequence below reflects the order that delivers fastest payback, eliminates rework, and builds the strongest foundation for subsequent stages. The sequencing is not a detail — it is where most programmes go wrong.

• 1. Energy management systems — Payback 1–3 years. The essential first step. Provides the metered, site-level data on which accurate solar sizing, battery dispatch, demand management, and ASRS-compliant Scope 2 reporting all depend. Supported by the Victorian Energy Upgrades scheme and the NSW Energy Savings Scheme.

• 2. Energy efficiency measures — Payback 1–7 years. Lighting and controls typically under three years; HVAC three to seven. Reduces base load before generation assets are added — improving solar sizing accuracy and the economics of every downstream technology. The most reliable returns in any programme.

• 3. Rooftop solar PV — Payback ~5 years nationally. For commercial systems above 100 kW, 2025 modelling of nearly 400 Australian business cases puts national average payback at 4.8 to 5.5 years, with IRRs typically above 25%. Returns vary significantly by state — Sydney and Adelaide lead; Melbourne is considerably longer due to lower retail tariffs and fewer sunshine hours. Small Scale Technology Certificates apply up to 100 kW; Large Scale Generation Certificates above that threshold.

• 4. Behind-the-meter battery storage — Payback ~7–9 years. Value comes from peak demand management, time-of-use arbitrage, resilience, and growing flexibility market participation from 2026. Note: FCAS ancillary services revenue has declined as the NEM battery fleet has grown — financial models should not rely on FCAS as a primary revenue source. The federal Cheaper Home Batteries Program (~30% discount from July 2025) applies primarily to residential systems; commercial eligibility requires per-site verification.

• 5. Fleet electrification and EV charging — Often total-cost-of-ownership positive. Workplace and depot charging enables fleet electrification, which frequently outperforms internal combustion when charging is managed against site generation. The FBT exemption for full battery electric vehicles (BEVs) valued below $91,387 remains in place, pending a government review reporting by mid-2027. PHEVs no longer qualify for new arrangements from April 2025.

• 6. Virtual power plant participation — Supplementary revenue. Treat as additional income, not a core investment driver. The commercial C&I flexibility market is structurally opening: aggregated DER will compete directly in the NEM from May 2027. Build asset capability now and position for participation as the market opens.

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THE DIGITAL LAYER IS NOT OPTIONAL

The difference between an onsite energy installation and an integrated energy system is the digital and AI infrastructure that connects them. Without it, assets operate in isolation, savings are not fully captured, reporting remains manual and error-prone, and flexibility market participation is technically impossible.

The minimum viable digital stack for a commercial site includes:

• Real-time monitoring across solar, storage, and key loads

• Demand forecasting and anomaly detection

• Automated battery dispatch against tariff signals

• Scope 2 calculations with audit-ready data trails aligned to ASRS

More advanced deployments add digital twin modelling for investment sizing, automated billing and flexibility revenue reconciliation, and Scope 3 supplier emissions integration.

One important dynamic: the NEM’s intraday price profile has shifted — negative midday prices in some states, elevated evening peaks. The value of battery dispatch is increasingly concentrated in the evening and in demand event management. Platforms that model and automate around this intraday structure extract materially higher returns from the same installed assets.

Organisations that deploy digital infrastructure alongside physical assets — not after — consistently achieve higher returns and reach ASRS compliance readiness faster.

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INCENTIVES IN 2025–26

Note: Incentive programmes change. Eligibility criteria, funding availability, and current status should be verified before programme design. The following reflects the position as at early 2026.

Commonwealth

• Small Scale Technology Certificates (STCs) — Solar PV up to 100 kW; reduces upfront cost at installation via the SRES.

• Large Scale Generation Certificates (LGCs) — Solar PV over 100 kW; ongoing revenue across the system’s generation life.

• Cheaper Home Batteries Program — Approximately 30% discount from July 2025; primarily residential/small-scale — verify commercial eligibility per site.

• Instant asset write-off — Consult a tax adviser on current thresholds; improves year-one cash position.

State and market

• Victorian Energy Upgrades — Efficiency, controls, solar; new large commercial solar incentive launched January 2026 — significant for Victorian operations.

• NSW Energy Savings Scheme — Efficiency and controls; strong for lighting and HVAC upgrades.

• AEMC C&I flexibility incentives — $50 million available from April 2026 ahead of full NEM market opening in May 2027.

• FBT exemption — BEVs — Full battery electric vehicles under $91,387 LCT threshold. PHEVs excluded from April 2025. Scheme under formal review; report due mid-2027.

• QLD, SA, WA state programmes — Funding cycles and availability vary materially by state — confirm current status before design.

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WHY SEQUENCING MATTERS MORE THAN TECHNOLOGY SELECTION

In well-executed programmes, the technology choices are rarely the source of underperformance. The sequencing is. Deploying solar before establishing a reliable metered load profile results in systems sized against estimates rather than actuals. Adding batteries before load optimisation reduces the demand cost savings those batteries were meant to capture. Participating in flexibility markets without compliant telemetry and adequate dispatchable capacity produces aggregator contracts that cannot be honoured.

The investment case for each stage also depends on the one before it: the economics of solar improve when base load is reduced through efficiency; the economics of batteries improve when solar generation is well-matched to load; the case for fleet electrification improves when there is daytime solar to charge against.

Getting the sequencing right is fundamentally a strategy and business case problem before it is a procurement or engineering one. That analysis is best done before capital is committed, not after.

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KEY RISKS TO MANAGE

• Network export limits require solar systems to be sized with export constraints from the outset — not adjusted afterward.

• Battery flexibility revenue should be modelled conservatively: FCAS ancillary revenues have declined to their lowest levels since 2020 as the NEM battery fleet has grown.

• The Cheaper Home Batteries Program discount was recalibrated in late 2025 as uptake outpaced budget projections — verify current commercial eligibility and discount levels directly.

• The FBT exemption for BEVs is under formal review with a mid-2027 report; model the scenario in which the scheme is modified for multi-year fleet strategies.

• High-quality metering data is not optional — it is the foundation on which accurate reporting, optimisation, and flexibility participation all depend.

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GG ADVISORY PERSPECTIVE

Onsite energy in 2025 to 2026 is not a technology selection exercise. It is a strategic decision with compounding financial and regulatory consequences. Generation, storage, efficiency, fleet electrification, and digital infrastructure need to be evaluated together — as an integrated system — before procurement begins. Organisations that approach them as separate decisions consistently underperform on both financial and sustainability metrics.

For Group 2 organisations whose first mandatory reporting period begins 1 July 2026, the three-year limited liability window for Scope 3 and transition plans is not a reason to defer. It is the window in which to establish the strategy, data foundations, and investment sequencing that will be required when full assurance obligations and penalty exposure attach.

GG Advisory supports commercial organisations to navigate the onsite energy landscape, design integrated strategies, and build the business cases that give decision-makers confidence before they commit capital. Our perspective is grounded in direct experience across energy strategy with Shell, ARENA, and Powerlink. If your organisation is evaluating its onsite energy strategy, we welcome a conversation.