This report is the deliverable for Milestones 1.4.1 of the FEnEx CRC’s Commonwealth Grant Agreement.
In 2023, the Australian government reformed the Safeguard Mechanism (SGM) to meet Paris Agreement targets. Currently, Australia’s LNG industry produces around 26% of the emissions produced by facilities covered by the SGM and 7.8% of Australia’s total emissions. Under the SGM the emissions intensities of LNG plants need to decline from an average of 0.47kgCO2-e/kgLNG in 2020 towards 0.4 kgCO2-e/kgLNG by 2030. Relative to 2020 levels, this is projected to reduce LNG annual emissions by around 5 MtCO2-e or 1.1% of Australia’s total.
This report analyses the nature of LNG plant GHG emissions and explores reduction strategies, focusing on methods that can deliver substantial abatement. The key pathways for emissions reduction in LNG plants include:
- Electrification
- Low Carbon Fuels
- Carbon Capture and Storage (CCS)
- Carbon Credits
In this report, the economics of CCS and electrification projects were compared to the option of purchasing carbon credits. The economic analysis generated order-of-magnitude CapEx values that put emitters in the same financial position as purchasing credits, i.e. breakeven CapEx values. This method of back-calculation rather than direct estimation of CapEx was used because costs of retrofits are highly site-specific and cannot be estimated for a general case; therefore, a breakeven CapEx in this report indicates the project cost required to make CCS or electrification a feasible alternative. Takeaways from the economic analysis are as follows:
- Because CCS directly captures and sequesters CO2 from emission sources, the feasibility of a CCS project is directly related to carbon credit price. Unlike CCS, electrification can eliminate fuel gas combustion on-site and convert legacy fuel gas streams into saleable product: LNG and potentially domestic gas. This commercial aspect of elecftrification has a greater influence of project feasibility than carbon credit price.
- Assuming a carbon credit price of AUD80 per tCO2-e, a breakeven CapEx of AUD621 million was back-calculated for a total CCS solution covering turbine exhaust CO2 and AGRU vent CO2 at a 4.9 Mtpa LNG plant. Current levelised costs of CCS technologies show that CCS projects cannot achieve CapEx values this low; therefore, purchase of credits presents a better financial option than retrofit of CCS.
- For electrification, the CapEx values required to breakeven relative to offset purchases were generally lower than the expected cost to implement electrification, suggesting AUD80 carbon credits typically present a better financial option than an electrification retrofit. Despite this general result, some high breakeven CapEx values (AUD3.5 billion, AUD2.4 billion) were found for cases with high LNG price (AUD20 per GJ) and low electricity price (AUD10 per MWh and below). This finding suggests that – in some circumstances – electrification may present a feasible alternative to only purchasing credits. AUD20 per GJ is a high yet credible LNG price based on recent price data for LNG in Asia, whereas electricity prices below AUD10 per MWh are not commonly available through grid connection in Australia.
- The actual cost to electrify an LNG plant used in our report, AUD1.2 billion, is based on a Foster Wheeler study for Angola LNG. The Foster Wheeler study considered electrification as a greenfield LNG plant project, not a retrofit project. In general, retrofits are more expensive than greenfield projects due to loss of LNG production, the inefficiency of construction work on live plants, and the complexity of retrofit design work. A detailed, site-specific analysis would be required to determine the feasibility of electrification and CCS for any particular LNG plant.
While our estimates are only indicative and cannot be generalised, they show that the economic feasibility of decarbonisation strategies depends on carbon credit price, LNG price, grid power costs, and capital expenditure. Electrification and CCS offer benefits under specific conditions, but in most retrofit scenarios they would require additional incentives to compete with carbon credits which are generally more economic given their current and projected cost. It is likely that LNG producers will use a combination of decarbonisation tools to meet their Safeguard targets following different pathways depending not only on economic factors, but also different conditions like location, climate, age of plant and the current and future regulatory and policy environment, which have not been discussed in this report.
Authors
- Dr Mauricio Di Lorenzo, FEnEx CRC Foundation Fellow & Curtin University
- Dr Luke McElroy, FEnEx CRC Engineering Study Manager
- Prof Michael Johns, University of Western Australia & FEnEx CRC Research Director
- Prof Eric May, FEnEx CRC CEO & University of Western Australia
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