Abstract
Green hydrogen produced from renewable electricity is central to Australia’s ambition to become a major exporter of low-emissions energy, yet its commercial prospects depend on delivered cost. This thesis develops a techno-economic model to estimate the levelised cost of hydrogen (LCOH) for a representative 500 MW electrolysis facility supplied by co-located solar and wind generation in a renewable-rich Australian export region. Using a capital-recovery-factor approach over a 25-year horizon, the base case yields an LCOH of A$4.75 per kilogram, of which purchased renewable electricity contributes 53 per cent. A four-scenario sensitivity analysis spanning electrolyser capital cost, capacity factor, electricity price and the weighted average cost of capital produces LCOH values ranging from A$2.47 to A$6.59 per kilogram. The findings indicate that electricity price and the cost of capital, rather than electrolyser capital cost alone, dominate competitiveness, and that Australian policy instruments such as Hydrogen Headstart can materially narrow the gap to export viability.
Introduction
Hydrogen is increasingly positioned as a versatile energy carrier capable of decarbonising sectors that resist direct electrification, including heavy industry, long-distance freight and high-temperature process heat. Global interest has intensified as governments seek complements to renewable electricity, and international agencies now anticipate that low-emissions hydrogen will underpin a substantial share of future clean-energy trade (IEA 2023). Australia has identified this emerging market as a strategic opportunity. Its combination of exceptional solar and wind resources, established trading relationships across the Indo-Pacific and existing energy-export infrastructure has led successive governments to frame hydrogen as a pillar of the nation’s low-carbon future through the National Hydrogen Strategy (DCCEEW 2024) and successive investment commitments administered by the Australian Renewable Energy Agency (ARENA 2023).
Hydrogen is conventionally classified by production pathway. So-called green hydrogen, generated by splitting water in an electrolyser powered by renewable electricity, is the only pathway that is genuinely zero-emissions at the point of production, in contrast to fossil-derived hydrogen produced from natural gas or coal (Bruce et al. 2018). The central obstacle to green hydrogen is not technical feasibility but cost: at present it remains considerably more expensive than incumbent fossil pathways, and the pace of cost reduction will determine whether an export industry becomes economically self-sustaining (IRENA 2020). Understanding the structure of that cost, and the parameters that drive it, is therefore essential for evidence-based policy and investment.
This thesis constructs a transparent techno-economic model of green hydrogen production for an Australian export setting. It is guided by three research questions:
- What is the levelised cost of hydrogen for a representative utility-scale green hydrogen export facility in Australia under current cost and financing conditions?
- Which techno-economic parameters most strongly influence the levelised cost of hydrogen?
- To what extent do plausible cost reductions and Australian policy instruments bring the delivered cost within a competitive export range?
The scope is confined to the production stage of the supply chain, that is, renewable generation, electrolysis and on-site storage, with the downstream conversion and shipping stages treated qualitatively in the discussion. The analysis adopts an Australian export perspective and draws on Australian cost and policy sources throughout, while remaining methodologically applicable to comparable jurisdictions.
Literature Review
Three electrolyser technologies dominate the literature. Alkaline electrolysis is the most mature and lowest in capital cost, proton exchange membrane (PEM) systems offer superior responsiveness to variable renewable input at a modest cost premium, and solid oxide electrolysis promises higher efficiency but remains at an earlier stage of commercial readiness (Reksten et al. 2022). Across all three, capital costs are projected to fall as manufacturing scales, with several analyses anticipating reductions of forty per cent or more by 2030 as gigawatt-scale production is established (IRENA 2020). Australian cost benchmarking through the CSIRO GenCost process has tracked these trajectories and reports steadily declining installed costs for electrolysis alongside continued falls in the cost of the solar and wind generation that supplies it (Graham et al. 2023).
A recurring finding is that the delivered cost of green hydrogen is governed less by the electrolyser itself than by the electricity that powers it and the intensity with which the plant is operated. Because electricity typically represents the single largest cost element, both the price of renewable energy and the electrolyser capacity factor exert a decisive influence on the levelised cost (Yates et al. 2020). This creates an inherent design tension: dedicated off-grid renewables can supply low-cost energy but deliver a lower and more variable capacity factor, whereas grid connection raises the capacity factor at the expense of higher and more carbon-intensive electricity, an issue of particular relevance in the National Electricity Market as it transitions (AEMO 2024; Longden et al. 2022).
Beyond production, the export proposition introduces the challenge of moving hydrogen over long distances. Gaseous hydrogen has a low volumetric energy density, so export requires either liquefaction, which is energy-intensive, or conversion to a chemical carrier such as ammonia or a liquid organic hydrogen carrier, each of which adds cost and energy penalties along the chain (IEA 2023). The choice of carrier interacts with the destination market and with the availability of reconversion infrastructure, and it represents a substantial component of the delivered cost that any export-oriented assessment must acknowledge.
Methodologically, the levelised cost of hydrogen has become the standard metric for comparing production pathways, mirroring the levelised cost of electricity used in power-sector analysis (Parkinson et al. 2019). However, published estimates vary widely because they rest on divergent assumptions about capital cost, capacity factor, electricity price and the cost of capital, and are frequently drawn from European or global datasets rather than Australian conditions (Yates et al. 2020). A transparent, Australian-parameterised model that isolates the sensitivity of the levelised cost to each driver, and that makes the capital-recovery calculation explicit, therefore remains a useful contribution and forms the basis of the present study.
Methodology
The study employs a deterministic techno-economic model that computes the levelised cost of hydrogen for a representative green hydrogen production facility. The system boundary, illustrated in Figure 1, encompasses co-located solar and wind generation, a desalinated water supply, the electrolyser and balance of plant, and on-site compression and storage, with the export carrier and shipping stages lying outside the modelled boundary and examined separately. The levelised cost is defined as the constant price per kilogram that equates the discounted revenue of the facility with its discounted lifetime costs, expressed as the sum of annualised capital cost and annual operating cost divided by annual hydrogen output.
Capital cost is annualised using the capital recovery factor, which converts an upfront investment into an equivalent uniform annual charge over the economic life of the asset:
CRF = [r (1 + r)n] / [(1 + r)n – 1]
where r is the weighted average cost of capital and n is the economic life in years. The levelised cost is then LCOH = (CRF x CAPEX + annual operating cost) / annual hydrogen output. The base-case parameters, drawn from Australian cost benchmarking and the wider literature, are set out in Table 1.
Table 1: Base-case parameters of the green hydrogen techno-economic model.
| Parameter | Base-case value |
|---|---|
| Electrolyser capacity | 500 MW |
| System specific energy consumption | 50 kWh per kg |
| Electrolyser capacity factor | 50 per cent |
| Annual hydrogen output | 43,800 tonnes |
| Total installed capital cost | A$800 million |
| Renewable electricity price | A$50 per MWh |
| Fixed operating cost (incl. water and stack replacement) | A$30 million per year |
| Economic life | 25 years |
| Weighted average cost of capital | 7 per cent |
| Capital recovery factor | 0.0858 |
To address the second and third research questions, a sensitivity analysis was constructed around four scenarios that vary the parameters identified in the literature as most influential: electrolyser capital cost, renewable electricity price, capacity factor and the weighted average cost of capital. An optimistic scenario reflects credible 2030 cost reductions, a pessimistic scenario reflects higher financing and input costs, and a stretch scenario reflects a mature industry with very low-cost firmed renewables. Each scenario was recomputed from first principles using the same formula, so that the results are internally consistent and directly comparable.
Results
The base-case levelised cost was calculated by substituting the parameters of Table 1 into the model. The capital recovery factor is derived first:
CRF = [0.07 x (1.07)25] / [(1.07)25 – 1] = (0.07 x 5.427) / (5.427 – 1) = 0.3799 / 4.427 = 0.0858
The annual quantities follow directly. Annual electricity consumption is 500 MW x 8,760 hours x 0.50 = 2,190,000 MWh, and annual hydrogen output is 2,190,000 MWh at 50 kWh per kg, which is 43,800,000 kg. The three cost streams are therefore:
- Annualised capital: CRF x CAPEX = 0.0858 x A$800 million = A$68.64 million
- Electricity: 2,190,000 MWh x A$50 per MWh = A$109.50 million
- Fixed operating cost: A$30.00 million
Summing these and dividing by annual output gives the levelised cost:
LCOH = (68.64 + 109.50 + 30.00) / 43.8 = 208.14 / 43.8 = A$4.75 per kg
The composition of this figure is set out in Table 2. Purchased renewable electricity is the single largest contributor at A$2.50 per kilogram, more than half of the total, while annualised capital accounts for roughly one third and fixed operating cost for the remainder.
Table 2: Base-case levelised cost of hydrogen decomposed by cost element.
| Cost element | Contribution (A$ per kg) | Share of LCOH |
|---|---|---|
| Renewable electricity (purchased) | 2.50 | 53% |
| Electrolyser and plant capital (annualised) | 1.57 | 33% |
| Fixed operating cost, water and stack replacement | 0.68 | 14% |
| Levelised cost of hydrogen | 4.75 | 100% |
The scenario analysis, reported in Table 3, demonstrates the sensitivity of the levelised cost to its principal drivers. Reducing capital cost, electricity price and the cost of capital while lifting the capacity factor, as in the optimistic 2030 scenario, lowers the levelised cost to A$3.60 per kilogram. The pessimistic combination of higher capital, dearer electricity, a lower capacity factor and a nine per cent cost of capital raises it to A$6.59 per kilogram. The stretch scenario, representing a mature industry with very cheap firmed renewables and low-cost capital, reduces the levelised cost to A$2.47 per kilogram, approaching but not reaching the widely cited aspiration of hydrogen below A$2 per kilogram.
Table 3: Levelised cost of hydrogen under four techno-economic scenarios.
| Scenario | Capital cost (A$m) | Electricity (A$/MWh) | Capacity factor | WACC | LCOH (A$/kg) |
|---|---|---|---|---|---|
| Base case | 800 | 50 | 50% | 7% | 4.75 |
| Optimistic (2030 cost-down) | 600 | 40 | 55% | 6% | 3.60 |
| Pessimistic (high-cost) | 1,000 | 65 | 45% | 9% | 6.59 |
| Stretch (mature industry) | 450 | 25 | 58% | 5% | 2.47 |
Across the four scenarios the levelised cost varies by a factor of 2.7, from A$2.47 to A$6.59 per kilogram. Decomposing the movement confirms that electricity price and the cost of capital, both of which act on the largest cost streams, drive the widest swings, whereas changes in electrolyser capital cost alone shift the result more modestly. This ordering directly answers the second research question and frames the discussion that follows.
Discussion
The results confirm that the economics of green hydrogen are dominated by the cost of renewable electricity and by the cost of capital, rather than by the electrolyser in isolation. Because electricity contributes 53 per cent of the base-case levelised cost, any reduction in the delivered price of firmed renewable energy flows almost proportionally into a lower hydrogen cost. The capacity factor operates on the same lever from the opposite direction: a higher factor spreads the fixed capital charge across more output, which is why the optimistic scenario benefits as much from lifting utilisation as from cheaper equipment. These findings are consistent with the Australian techno-economic literature, which likewise identifies electricity price and utilisation as the decisive variables (Yates et al. 2020; Graham et al. 2023). The prominence of the weighted average cost of capital is equally important for policy, since it implies that measures reducing financing risk can lower the delivered cost without any change in the underlying technology (Longden et al. 2022).
These cost drivers explain why Australian policy has concentrated on de-risking early projects and underwriting revenue rather than merely subsidising equipment. The Hydrogen Headstart program provides production credits designed to bridge the gap between the cost of green hydrogen and the price the market will currently bear, functioning in effect as a contract that guarantees a portion of revenue over the early operating years (DCCEEW 2024). A credit of a few dollars per kilogram, set against a base-case levelised cost of A$4.75, is sufficient to move a representative project from unviable to bankable, which is consistent with the modelled sensitivity. Complementary measures reinforce this effect: the Australian Renewable Energy Agency has funded electrolyser demonstration at increasing scale to accelerate the capital-cost reductions embedded in the optimistic scenario (ARENA 2023), while the Guarantee of Origin scheme administered by the Clean Energy Regulator certifies the emissions intensity of each shipment, allowing genuinely low-emissions Australian hydrogen to command a premium in environmentally discerning markets (Clean Energy Regulator 2024).
Competitiveness must ultimately be judged on delivered cost, not production cost alone. The levelised costs reported here cover production to the point of on-site storage; converting hydrogen to an exportable carrier such as ammonia or liquefied hydrogen, shipping it and reconverting it at the destination add materially to the final figure, so that a production cost near A$4.75 per kilogram may translate into a delivered cost several dollars higher in an Asian import market (IEA 2023). This reinforces the conclusion that unsubsidised export competitiveness depends on reaching the lower end of the modelled range. The stretch scenario of A$2.47 per kilogram, though demanding, is not implausible for the best Australian sites given continued falls in renewable and electrolyser costs, and the growing project pipeline recorded in the national hydrogen database suggests that developers are positioning for exactly this trajectory (CSIRO 2024). The convergence of abundant resources, targeted policy support and a maturing cost base therefore offers a credible, if not guaranteed, pathway to a competitive Australian export industry.
Several limitations qualify these conclusions. The model is deterministic and does not capture the correlated variability of solar and wind output, which in practice constrains the achievable capacity factor for off-grid configurations. It also excludes carrier conversion and shipping from the quantified boundary, and it assumes a single-point electricity price rather than an hourly dispatch against a real renewable profile. Extending the analysis to a stochastic, hourly framework, and quantifying the full delivered-cost chain, would strengthen the evidence base and represents a natural direction for further work.
Conclusion
This thesis developed a transparent techno-economic model of green hydrogen production for an Australian export setting and used it to estimate the levelised cost of hydrogen and its sensitivity to the principal cost drivers. Under base-case conditions the levelised cost is A$4.75 per kilogram, dominated by the price of renewable electricity, and across four internally consistent scenarios it ranges from A$2.47 to A$6.59 per kilogram. The analysis shows that electricity price, capacity factor and the cost of capital, rather than electrolyser capital cost alone, determine whether an export project is competitive. These parameters are precisely those that Australian policy instruments target: production credits through Hydrogen Headstart address revenue risk, demonstration funding through the Australian Renewable Energy Agency accelerates cost reduction, and the Guarantee of Origin scheme enables low-emissions hydrogen to be verified and valued. The central implication is that competitiveness will be achieved not through a single technological breakthrough but through the simultaneous reduction of energy cost, financing cost and delivery cost. Provided these reductions materialise, and are supported by stable policy, the modelling indicates a credible pathway for Australia to convert its renewable endowment into a viable green hydrogen export industry.
References
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