Introduction and methodology

This report examines the “missing middle” segment of Australia’s energy market, comprising commercial and industrial (C&I) systems between 100 kilowatts and 30 megawatts. Despite high daytime loads and large roof areas, deployment of solar, battery storage, and flexible load management remains below technical and economic potential. The study identifies structural, regulatory, and commercial barriers suppressing deployment and proposes a national reform blueprint. The findings are based on a literature review of more than 80 sources, a member survey of 61 industry participants, and ten in-depth interviews with practitioners spanning measurement, verification, property management, and installation.

Key findings

Financial return is the primary driver of C&I investment, with 94.7% of survey respondents citing cost savings as a top priority. While the economics of solar and storage are strengthening, value is increasingly tied to flexibility rather than energy arbitrage. Confidence in the business case is moderate, averaging 2.88 out of 4, reflecting fragility under tariff volatility and connection delays. Payback periods have stretched to approximately four years for solar and nine years with batteries, largely due to the collapse of Large-scale Generation Certificate (LGC) prices to roughly $3 to $4, down from historical highs of $20 to $30. One practitioner reported that quote-to-contract conversion rates fell from eight in ten to approximately one in ten due to this price crash.

Connection processes and network constraints are identified as the dominant barrier to deployment. Survey data shows 70.9% of respondents cite the length of Distribution Network Service Provider (DNSP) approval times as a leading challenge, while 82.1% identify connection requirements as the area where governance is least consistent. 85% of respondents reported that connection issues sometimes or frequently change system designs or commercial outcomes materially. Furthermore, current tariff structures, particularly demand charges, are the single largest influence on system sizing decisions for 63% of respondents, yet only 2% believe current tariffs support investment in flexibility and storage very well.

Data access and interoperability remain foundational constraints. 81.4% of respondents rate interoperability issues as significant, and 60.9% describe access to hosting capacity and real-time network data as poor or limited. Misalignment between landlords and tenants is another persistent barrier; 45.5% of respondents report that split incentives often or almost always create investment hurdles. This is compounded by a structural mismatch between 15-to-20-year Power Purchase Agreement (PPA) terms and typical three-to-seven-year commercial leases.

Strategic recommendations

The report proposes several priority reforms to unlock the sector. Regulators and distribution networks should establish mandatory connection timeframes with enforceable performance metrics. A capped-export, reduced-administration pathway for systems in the 100 to 500 kilowatt range, informed by the German 2024 reform model, should be trialled. Additionally, the Commonwealth Government should restore a credible price signal by establishing a successor to the LRET or a bespoke mid-scale mechanism that delivers a certificate price in the $20 to $25 per megawatt-hour range.

Expanding the Small-scale Renewable Energy Scheme (SRES) threshold to at least 1 megawatt is recommended to eliminate artificial under-sizing currently driven by the 100 kilowatt cliff edge. Other proposed measures include legislating an accelerated depreciation allowance for solar and battery assets and establishing a standardised commercial green lease framework to resolve split-incentive issues. National data access standards should be mandated to provide low-cost access to hosting capacity and feeder constraint information.

Case studies illustrate the impact of these barriers. A Port Melbourne food manufacturer was unable to proceed with a 2-megawatt solar and 7-megawatt-hour battery project because revenue streams from arbitrage and frequency control ancillary services (FCAS) were too volatile to support financing. A hybrid wind-battery and solar project saw connection costs escalate from an initial $250,000 quote to a final cost of $1.6 million due to feeder upgrades. In another instance, a steel manufacturer was charged for exporting solar energy during negative price periods, leading them to disable export and reduce the system’s value. Finally, a cold storage tenant’s project stalled when the landlord demanded payment for electricity generated by the tenant-funded system, highlighting the need for standardised benefit-allocation frameworks.