2020 Global demand for hydrogen was around 90 million tonnes (Mt) a year. The ‘IEA Net Zero Emissions by 2050’ scenario, expects this demand to expand by 44% by 2030, of which low-carbon hydrogen will amount to 21Mt.
Low-carbon hydrogen is hydrogen that is produced in a way that creates little to no GHG emissions. These include green, blue and turquoise hydrogen.
Of these routes, Turquoise is the least known, it is zero emissions, does not need CO2 capture or sequestration and needs only a fifth of the energy required for electrolysis of water.
This paper will carry out a comparison of three hydrogen production routes, comparing their levelized cost of hydrogen and key metrics. This is then further broken down for Methane Pyrolysis into a comparison of two vying technologies. The following low carbon hydrogen routes are therefore compared in this techno-economic evaluation.
1) Blue Hydrogen – Autothermal Reforming with CO2 capture
2) Turquoise Hydrogen –
a. Catalytic Methane Pyrolysis
b. Non-Catalytic Plasma/Microwave Methane Electrolysis
3) Green Hydrogen – Water Electrolysis
The Paper Objectives are as follows:
• Compare the key techno-economic features of blue hydrogen, green hydrogen and turquoise hydrogen (both catalytic and non-catalytic)
• Investigate how the corresponding feasibilities change with scale. Working through various scales for the example project.
• Assess the impact of variable Renewable supply on Green & Turquoise Hydrogen with storage opportunities and how this can influence their optimal configuration, feasibility, and performance in contrast to the steady state blue hydrogen facility.

In an effort to reduce greenhouse gas emissions, the Australian government legislated the Safeguard Mechanism (SGM) in 2016. It is generally accepted that it had minimal impact, with no material reduction in greenhouse gas emissions resulting. In a move to address this, the legislation was amended, effective July 2023.
These amendments rewrote the rules - baselines will reduce over time, the method of setting them will change, new concepts such as ‘international best practice’ will be introduced and new projects (including those already sanctioned, but not yet onstream) will be subject to tougher requirements.
Our analysis will review the impact on the upstream projects currently covered by the SGM, and a select group of new projects. We will give our view on how the transition from the facility-specific to industry-average baselines impacts operators, and identify some of the potential winners and losers.
Although first reporting is not due until the end of the 2024 financial year, there is still significant uncertainty on how the amended SGM will operate, specifically with regards to "industry best practice". The paper will analyse what this could mean, and potential impacts. Is the SGM the roadmap to net zero that the industry is looking for?
The work will leverage Wood Mackenzie’s asset by asset emissions data, and our unique insight into the economics of upstream developments. Ultimately, we will assess the trade-off that has been made by the Australian government - emissions for commerciality – and its long-term impact on the upstream sector.

A comprehensive assessment of the respective Federal petroleum and greenhouse gas (GHG) storage legislation has been undertaken, in part to understand the rationale underpinning the derivative GHG regulations. The assessment examined the interactions between the technical requirements in the GHG legislation (for regulatory approval) and the existing and likely future technical capabilities of the CCS industry and stress-tested real-world CCS project examples against the existing GHG legislation.
The review has identified several fundamental inconsistencies in the GHG legislation that have the potential to result in projects experiencing substantial regulatory delays, namely:
- A “CO2 plume” is nowhere defined in legislation, even though the spatial location of a plume is central to numerous approvals, such as declaration of storage, demonstrating containment and all MMV programs.
- The regulatory concept of "containment" requires that a “plume” does not leave an approved storage formation or GHG permit, irrespective of the impact, or lack thereof, that this loss of “containment” might have. This concept, when combined with the lack of definition of a plume, represents a fundamental project risk; this could be addressed through a changed regulatory emphasis to potential “deleterious impacts”.
- There are opportunities to substantially improve the GHG permitting process via a streamlined and more spatially focused approach, which would maximise the efficient use of Australia’s available storage resources.
- A lack of a framework to manage future CCS project interactions at a basin-scale.
Our proposed solutions to the above issues will greatly support the CCS project roll-out if adopted.

We present the inputs and results of a discounted cash flow model which details the requirements for an import terminal to eventualize. The key requirement is high certainty cash flows from foundation users. This can be made possible through capacity booking which can be potentially underwritten by governments to ensure security of supply during peak winter months. The out-chartering of the FSRU vessel to serve as an LNG carrier during the peak Northern Winter will provide an additional revenue source. We also analyze the legacy supply decline and various price setting mechanisms for the Southern states which will soon turn net importers. We will describe the status of the four projects in the pipeline and identify milestones. We conclude that an import terminal provides an alternative proposition in the southern states considering the highly seasonal demand profile, the decline of Gippsland Basin production, and the relative inflexibility of Coal Seam Gas. Further, FSRUs can be redeployed to other regions, which reduces stranded asset risk from pipeline expansions, given Australia's net zero targets.