Executive Summary
This report assesses the technical and financial feasibility of installing a behind-the-meter solar photovoltaic (PV) and battery energy storage system at a hypothetical medium-sized manufacturing facility (referred to throughout as the Facility) located on an industrial estate near Wagga Wagga in the New South Wales Riverina. The Facility operates a two-shift production pattern six days a week, draws 1,850 megawatt hours (MWh) of grid electricity a year and carries a maximum demand of 520 kilowatts (kW), which together generate an annual electricity bill of approximately A$572,000 under its current commercial demand tariff. The proposed system pairs a 600 kilowatt-peak (kWp) rooftop array with a 600 kilowatt hour (kWh) battery rated at 300 kW. Modelling indicates the system would generate 883 MWh a year, lift on-site self-consumption to 92.4 per cent and cut grid imports by 44.1 per cent. At an installed cost of A$1.32 million it returns a net annual saving of about A$257,000, a simple payback of 5.1 years, a discounted payback of 6.3 years and a ten-year net present value of A$571,600 at a 6 per cent real discount rate. The levelised cost of the solar generation is 7.75 cents per kilowatt hour (c/kWh), well below the 30.9 c/kWh effective grid price, and the system abates roughly 539 tonnes of carbon dioxide equivalent (tCO2e) a year. The investment is recommended, with the battery scope treated as a resilience and self-consumption decision rather than a pure payback decision.
Introduction
Australian manufacturers face sustained pressure on electricity costs as wholesale prices in the National Electricity Market remain elevated and volatile relative to the pre-2022 period, and as network and demand charges continue to rise for commercial and industrial (C&I) customers (AEMO 2024; AER 2024). At the same time the installed cost of rooftop solar and lithium-ion battery storage has fallen substantially, making behind-the-meter generation one of the most accessible levers a mid-sized industrial site has for reducing operating cost and Scope 2 emissions (CEC 2024; CSIRO & AEMO 2024). For a daytime-intensive manufacturer, on-site solar is particularly attractive because a large share of generation can be consumed directly, displacing grid electricity at the full retail rate rather than being exported at a low feed-in price (ARENA 2023).
The aim of this report is to determine whether a solar-plus-battery installation at the Facility is technically sound and financially justified. The scope covers the site energy profile and current tariff, the sizing and expected energy balance of a proposed system, a financial appraisal comprising capital cost, annual savings, levelised cost of energy, payback and net present value, the greenhouse gas abatement achieved, and a sensitivity analysis of the key value drivers including the tariff and the small-scale and large-scale renewable energy incentives. Detailed structural assessment of the roof, switchboard protection design and procurement are acknowledged as necessary subsequent steps but sit outside the boundary of this feasibility study. All figures are in Australian dollars.
Site Energy Profile and Tariff
The Facility’s load is dominated by extrusion, moulding and compressed-air plant that runs across two shifts, so consumption is concentrated in daylight and early-evening hours. Metered data for the most recent financial year show an annual consumption of 1,850,000 kWh and a maximum demand of 520 kW. The resulting load factor is moderate and typical of a two-shift operation:
Load factor = annual consumption ÷ (maximum demand × 8,760 hours) = 1,850,000 ÷ (520 × 8,760) = 1,850,000 ÷ 4,555,200 = 0.406, or 40.6 per cent.
Approximately 68 per cent of consumption falls within the 0700 to 1700 window, which is the single most important determinant of solar value because it sets the ceiling on how much generation can be self-consumed without storage (ARENA 2023). The site is billed on a commercial time-of-use demand tariff comprising a peak energy charge of 31.5 c/kWh, an off-peak energy charge of 17.0 c/kWh, a demand charge of A$14.20 per kW of monthly maximum demand and a daily supply charge of A$8.40. On a 62 to 38 split between peak and off-peak consumption, the current annual bill is composed as follows: peak energy of 1,147,000 kWh at 31.5 c/kWh gives A$361,305; off-peak energy of 703,000 kWh at 17.0 c/kWh gives A$119,510; demand charges of 520 kW × A$14.20 × 12 give A$88,608; and supply charges of A$8.40 × 365 give A$3,066. The total is A$572,489, an effective all-in price of 30.9 c/kWh. The demand component, at over 15 per cent of the bill, is significant and creates a clear role for storage in shaving the monthly peak.
Proposed System Design and Energy Balance
The proposed configuration is a 600 kWp north-facing rooftop array coupled with a 600 kWh battery rated for 300 kW of continuous output, giving a two-hour storage duration. The array is sized to the available roof area and to the daytime load rather than to annual consumption, so that the great majority of output is consumed on site. The design would be installed to AS/NZS 5033 for the array and connected under AS/NZS 4777.1 for inverter grid connection, using Clean Energy Council accredited equipment and installers (Standards Australia 2021; Standards Australia 2016). Table 1 sets out the system configuration and the resulting annual energy balance, and Figure 1 illustrates the annual energy flows between the array, the battery, the grid and the load.
Table 1: Proposed system configuration and annual energy balance
| Parameter | Unit | Value |
|---|---|---|
| PV array capacity | kWp | 600 |
| Assumed capacity factor (Riverina, fixed tilt) | % | 16.8 |
| Specific yield | kWh/kWp | 1,472 |
| Annual generation | kWh | 883,000 |
| Battery power rating | kW | 300 |
| Battery usable capacity | kWh | 600 |
| Battery round-trip efficiency | % | 90 |
| Direct self-consumption (solar to load) | kWh | 636,000 |
| Battery discharge to load | kWh | 180,000 |
| Total on-site solar use | kWh | 816,000 |
| Self-consumption rate | % | 92.4 |
| Exported to grid | kWh | 47,000 |
| Grid import before system | kWh | 1,850,000 |
| Grid import after system | kWh | 1,034,000 |
| Grid import reduction | % | 44.1 |
Worked calculations: generation and self-consumption
The headline energy figures in Table 1 are derived as follows, with the formula, the substitution and the result shown for each.
Annual generation = installed capacity × capacity factor × 8,760 hours = 600 × 0.168 × 8,760 = 883,008 kWh, rounded to 883 MWh. The equivalent specific yield is 883,008 ÷ 600 = 1,472 kWh per kWp, which is consistent with a well-oriented fixed array in the inland Riverina climate zone (Blakers, Stocks & Lu 2021).
Direct self-consumption is estimated at 636,000 kWh, or 72.0 per cent of generation, given the 68 per cent daytime load share. The surplus available to the battery is 883,000 – 636,000 = 247,000 kWh. The battery charges with 200,000 kWh of this surplus and, at 90 per cent round-trip efficiency, returns 200,000 × 0.90 = 180,000 kWh to the evening load. Total on-site solar use is therefore 636,000 + 180,000 = 816,000 kWh.
Self-consumption rate = (total on-site solar use ÷ annual generation) × 100 = (816,000 ÷ 883,000) × 100 = 92.4 per cent. Grid imports fall by 816,000 kWh, from 1,850,000 to 1,034,000 kWh, a reduction of 44.1 per cent. Only 47,000 kWh, or 5.3 per cent of generation, is exported, which is the intended outcome of sizing the array to the load rather than to consumption.
Financial Appraisal
Capital cost and incentives
The estimated installed cost is A$1.32 million, comprising A$690,000 for the PV array at A$1,150 per kWp, A$510,000 for the battery at A$850 per kWh, and A$120,000 for balance-of-system works, engineering, procurement and the network connection. These unit rates sit within the range reported for C&I installations of this scale (CEC 2024; CSIRO & AEMO 2024). A point of regulatory importance is that the 600 kWp array exceeds the 100 kW threshold of the Small-scale Renewable Energy Scheme, so it is not eligible for upfront Small-scale Technology Certificates (Clean Energy Regulator 2024b). Instead it accrues Large-scale Generation Certificates (LGCs) under the Large-scale Renewable Energy Target, at one certificate per MWh generated, which could be created and sold until the scheme closes in 2030 (Clean Energy Regulator 2024a). Because LGC prices have been volatile and the scheme is time-limited, the base case conservatively excludes LGC revenue and treats it as upside, quantified in the sensitivity analysis.
Annual savings
The system saves money in three ways: by displacing imported energy with self-consumed solar, by reducing billed maximum demand, and by earning a modest feed-in payment on exports. The worked components are as follows.
Energy-charge saving = on-site solar use × blended avoided import price = 816,000 kWh × A$0.30 = A$244,800. The blended avoided price of 30 c/kWh reflects that self-consumed solar and battery discharge displace mainly peak and shoulder consumption.
Demand-charge saving = reduction in billed maximum demand × demand rate × 12 months = 140 × A$14.20 × 12 = A$23,856. A 140 kW reduction is a conservative estimate of the battery’s peak-shaving contribution, since the coincident afternoon peak can be reliably supported by stored energy.
Export revenue = exported energy × feed-in tariff = 47,000 kWh × A$0.05 = A$2,350. Gross annual saving is therefore 244,800 + 23,856 + 2,350 = A$271,006. Net of estimated operating and maintenance costs of A$14,000 a year for cleaning, monitoring, insurance and inverter servicing, the net annual saving is A$257,006, rounded to A$257,000.
Levelised cost of energy
The levelised cost of energy (LCOE) is the lifetime cost of solar generation per unit of output and tests whether generating on site is cheaper than buying from the grid. It annualises the capital cost over the array’s design life using a capital recovery factor (CRF):
CRF = [i(1 + i)n] ÷ [(1 + i)n – 1], where i = 6 per cent (real discount rate) and n = 25 years. With (1.06)25 = 4.2919, CRF = (0.06 × 4.2919) ÷ (4.2919 – 1) = 0.25751 ÷ 3.2919 = 0.0782.
LCOE = (PV capital × CRF + annual O&M) ÷ annual generation = (760,000 × 0.0782 + 9,000) ÷ 883,000 = (59,432 + 9,000) ÷ 883,000 = 68,432 ÷ 883,000 = A$0.0775/kWh, or 7.75 c/kWh. Here the PV share of capital is A$760,000 and the PV share of O&M is A$9,000. At 7.75 c/kWh the solar generation costs roughly one quarter of the 30.9 c/kWh grid price, the fundamental reason the investment is attractive, and it aligns with international cost benchmarks (IRENA 2023).
Payback and net present value
Simple payback = total installed cost ÷ net annual saving = 1,320,000 ÷ 257,000 = 5.1 years. Simple payback ignores the cost of capital, so the discounted cash flow schedule in Table 2 is used to derive a discounted payback and a net present value. Savings are held constant in real terms, on the assumption that electricity price escalation broadly offsets panel degradation, and are discounted at a 6 per cent real rate consistent with the Facility’s cost of capital in the prevailing interest-rate environment (RBA 2024).
Table 2: Ten-year discounted cash flow at a 6 per cent real discount rate (outflows in brackets)
| Year | Net cash flow (A$) | Discount factor at 6% | Present value (A$) | Cumulative PV (A$) |
|---|---|---|---|---|
| 0 | (1,320,000) | 1.0000 | (1,320,000) | (1,320,000) |
| 1 | 257,000 | 0.9434 | 242,454 | (1,077,546) |
| 2 | 257,000 | 0.8900 | 228,730 | (848,816) |
| 3 | 257,000 | 0.8396 | 215,777 | (633,039) |
| 4 | 257,000 | 0.7921 | 203,570 | (429,469) |
| 5 | 257,000 | 0.7473 | 192,056 | (237,413) |
| 6 | 257,000 | 0.7050 | 181,185 | (56,228) |
| 7 | 257,000 | 0.6651 | 170,931 | 114,703 |
| 8 | 257,000 | 0.6274 | 161,242 | 275,945 |
| 9 | 257,000 | 0.5919 | 152,118 | 428,063 |
| 10 | 257,000 | 0.5584 | 143,509 | 571,572 |
| Total | 1,250,000 | 1,891,572 | 571,572 |
The cumulative present value turns positive during Year 7, so the discounted payback is Year 6 plus the fraction of Year 7 required to recover the remaining A$56,228: discounted payback = 6 + (56,228 ÷ 170,931) = 6 + 0.33 = 6.3 years. The net present value over ten years is the sum of discounted savings less the capital outlay, A$1,891,572 – A$1,320,000 = A$571,572, and the benefit-cost ratio is 1,891,572 ÷ 1,320,000 = 1.43. Because the array’s design life is 25 years, the ten-year horizon understates the full lifetime return and should be read as a deliberately conservative test; even so, the project clears every criterion.
Emissions abated
Displacing grid electricity reduces the Facility’s Scope 2 emissions in proportion to the New South Wales grid emissions factor published in the National Greenhouse Accounts, which underpin reporting under the National Greenhouse and Energy Reporting scheme (DCCEEW 2024). Annual abatement = grid electricity displaced × emissions factor = 816 MWh × 0.66 tCO2e/MWh = 539 tCO2e per year. Counting the 47 MWh exported, which displaces generation elsewhere on the network, total displacement approaches 570 tCO2e a year. Over the 25-year life of the array, allowing for gradual output degradation, cumulative abatement is approximately 12,500 tCO2e, a material contribution to any corporate emissions-reduction commitment.
Sensitivity Analysis
The base-case result is attractive but rests on assumptions about the tariff, the capital cost, the discount rate and the treatment of renewable-energy incentives. Table 3 tests the sensitivity of the net annual saving, simple payback and ten-year net present value to plausible movements in each driver.
Table 3: Sensitivity of key financial outcomes to changes in the main value drivers
| Scenario | Year-1 net saving (A$) | Simple payback (years) | 10-year NPV at 6% (A$) |
|---|---|---|---|
| Base case (600 kWp PV + 600 kWh battery) | 257,000 | 5.1 | 571,600 |
| Import tariff +20% (higher grid prices) | 310,700 | 4.2 | 966,800 |
| Import tariff -20% (lower grid prices) | 203,300 | 6.5 | 176,300 |
| Capital cost +15% (supply-chain, exchange rate) | 257,000 | 5.9 | 373,500 |
| Capital cost -15% (competitive tender) | 257,000 | 4.4 | 769,500 |
| Discount rate 8% (higher cost of capital) | 257,000 | 5.1 | 404,500 |
| LGCs monetised at A$35/MWh to 2030 | 287,900 | 4.6 | 701,700 |
| PV-only design (no battery) | 201,000 | 3.8 | 719,400 |
Three findings stand out. First, the economics are robust: the ten-year net present value stays positive across the full range tested, including a 20 per cent fall in the tariff. The tariff is the dominant driver, since avoided energy is the largest saving, so the current environment of elevated C&I prices strengthens rather than weakens the case (AEMO 2024; AER 2024). Second, monetising LGCs shortens the simple payback to 4.6 years, but because the scheme closes in 2030 this upside is best treated as a bonus rather than a foundation of the investment decision (Clean Energy Regulator 2024a). Third, and most importantly for the design, the PV-only option has the fastest simple payback at 3.8 years and a comparable net present value, because the battery adds roughly 42 per cent of the capital while contributing a smaller share of the savings. The battery therefore has to be justified on grounds beyond simple payback, namely higher self-consumption, demand-charge certainty and partial operational resilience during grid outages, which are valuable to a manufacturer with continuous process loads (ARENA 2023).
Recommendations
- Proceed with the 600 kWp rooftop solar array as the priority investment, since it delivers the bulk of the savings, has an LCOE of 7.75 c/kWh against a 30.9 c/kWh grid price and pays back well inside its 25-year life.
- Commission a detailed structural and electrical assessment of the roof and main switchboard, and confirm the design against AS/NZS 5033 and AS/NZS 4777.1 before procurement, so that the installed cost estimate can be firmed up.
- Treat the 600 kWh battery as a separate, staged decision justified by self-consumption, demand-charge reduction and resilience rather than by simple payback, and consider deferring or scaling it once twelve months of post-solar interval data are available.
- Register the array under the Large-scale Renewable Energy Target and monitor LGC prices, creating certificates while they retain value ahead of the 2030 scheme closure, without relying on that revenue in the investment case (Clean Energy Regulator 2024a).
- Negotiate the supply contract and demand-tariff structure with the retailer in parallel, since the value of self-consumption and peak-shaving depends directly on the peak energy and demand rates the Facility is billed.
- Incorporate the estimated 539 tCO2e of annual abatement into the Facility’s National Greenhouse and Energy Reporting disclosures and any corporate emissions target, and re-verify it against the prevailing published grid emissions factor at commissioning (DCCEEW 2024).
Conclusion
The feasibility analysis supports investment in on-site solar at the Facility and a conditional case for adding battery storage. A 600 kWp array paired with a 600 kWh battery would generate 883 MWh a year, lift self-consumption to 92.4 per cent, cut grid imports by 44.1 per cent and abate about 539 tCO2e annually. At an installed cost of A$1.32 million it returns roughly A$257,000 a year, a simple payback of 5.1 years, a ten-year net present value of A$571,600 and a solar LCOE of 7.75 c/kWh, far below the grid price. The sensitivity analysis confirms the result holds across a wide range of tariff, cost and discount-rate assumptions, while also showing that the solar array alone is the stronger pure-payback proposition and that the battery must be justified on self-consumption and resilience grounds. The recommended path is to proceed with the solar array without delay, to confirm the engineering and tariff assumptions, and to treat the battery as a staged decision informed by post-installation load data. Managed on those terms, the project is both technically sound and financially compelling for a daytime-intensive Australian manufacturer facing sustained grid-price pressure.
References
Australian Energy Market Operator (AEMO) 2024, Quarterly energy dynamics: Q4 2024, Australian Energy Market Operator, Melbourne.
Australian Energy Regulator (AER) 2024, State of the energy market 2024, Australian Energy Regulator, Melbourne.
Australian Renewable Energy Agency (ARENA) 2023, Behind-the-meter battery storage for commercial and industrial energy users, Australian Renewable Energy Agency, Canberra.
Blakers, A, Stocks, M & Lu, B 2021, ‘Pathways to 100 per cent renewable electricity for Australia’, Progress in Photovoltaics: Research and Applications, vol. 29, no. 9, pp. 1093-1105.
Clean Energy Council (CEC) 2024, Clean energy Australia report 2024, Clean Energy Council, Melbourne.
Clean Energy Regulator 2024a, Large-scale Renewable Energy Target, Clean Energy Regulator, Canberra.
Clean Energy Regulator 2024b, Small-scale Renewable Energy Scheme, Clean Energy Regulator, Canberra.
CSIRO & AEMO 2024, GenCost 2023-24: final report, Commonwealth Scientific and Industrial Research Organisation, Canberra.
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International Renewable Energy Agency (IRENA) 2023, Renewable power generation costs in 2022, International Renewable Energy Agency, Abu Dhabi.
Reserve Bank of Australia (RBA) 2024, Statement on monetary policy, November 2024, Reserve Bank of Australia, Sydney.
Standards Australia 2016, AS/NZS 4777.1:2016 Grid connection of energy systems via inverters, Part 1: Installation requirements, Standards Australia, Sydney.
Standards Australia 2021, AS/NZS 5033:2021 Installation and safety requirements for photovoltaic (PV) arrays, Standards Australia, Sydney.