Australis Oil and Gas Limited provided its YE2021 reserve and resource update as independently assessed by Ryder Scott Company L.P. with an effective date of 31 December 20211. Australis continues to take a conservative approach to estimating its oil and gas reserves and resources. Future production from existing wells has been assessed in the YE2021 report in a manner consistent with previous years.

However, given the current Company strategy to introduce a partner for the purposes of advancing the development of its TMS asset, the Board has determined that it would not be appropriate to propose a development plan as part of the YE2021 reserves evaluation. Therefore, the YE2021 reserve and resource estimate consists of a proved, probable and possible developed reserve estimate only and no reserve estimates have been generated for undeveloped acreage. A contingent resource estimate is provided and, as in previous years, the mid case 2C contingent resource is subject to a qualifying development plan to transition volumes to an appropriate reserve category of proved, probable and possible.

Net Oil Developed Reserves: Ryder Scott made the following estimates1 of developed recoverable oil volumes, net to Australis. Proved ­ 2.98 MMbbls (-18%), Probable & Proved ­ 3.67 MMbbls (-11%), Possible, Probable & Proved ­ 4.54 MMbbls (-4%). The NPV(10) of the PDP reserves is US$62 million using a flat oil price of $67.27/bbl.

Ryder Scott have made the following estimates1 of low, mid and high case contingent resources. 1C ­ 23.40 MMbbls (+13%), 2C ­ 148.99 MMbbls (0%), 3C ­ 269.87 MMbbls (0%). At the effective date of the report, 31 December 2021, Australis held the rights to ~98,000 net acres within the TMS Core area, a reduction of about 10,000 acres during 2021.

Australis also divested its interests in 5 marginal TMS wells located in Louisiana outside the TMS core area, which reduced the existing operated well count to 33, of which two were shut in awaiting workovers for the entire year and were therefore designated Proved Developed Not Producing. The remaining 31 producing operated wells and interests in 15 producing non-operated wells were assessed by Ryder Scott on a Proved Developed Producing basis and additional volumes attributed to the mid (probable) and high (possible) cases. In previous years Australis has proposed modest development plans for Ryder Scott to consider in order to assess proved, probable and possible undeveloped reserves.

These development plans were based on an appropriate projected well schedule at that time and any recoverable volumes not assigned as an undeveloped reserve were allocated to a low, mid or high case contingent resource, subject only to a qualifying development plan. Australis has consistently advised that the Company has been seeking to introduce a partner in the TMS to help progress field development. The Australis Board therefore deemed it appropriate to wait and intends to update the undeveloped reserve assessment when there is more clarity on future development plans.

This decision does not impact the economic potential of the play. As shown in the YE2020 reserve report, which included a modest development program, the proved undeveloped reserves were economic even at the YE2020 reserve report oil price of US$47.02/bbl. Without a development plan all recoverable oil volumes from future wells are allocated to contingent resources.

The ASX and SPE compliant methodology of taking the average 1st day of the preceding 12-month period yielded an oil price of $67.27/bbl for use within the YE2021 report. The NPV(10) of the net PDP reserves volume is US$61.76 million, which is an increase of 30% from the YE2020 value, predominantly due to the higher oil price assumption for the YE2020 report of USD67.27/bbl. Key assumptions used by Ryder Scott to generate the YE2021 estimates are as follows: Reserves and contingent resources estimates are based on the deterministic estimation method.

The oil price used for all reserves analysis in this report is a flat realised $67.27/bbl, which is based on the average achieved price by Australis on the first day of the trailing 12 months of 2021. Operating costs for developed producing wells are based on the average of actuals incurred between December 2020 and November 2021. The existing PDP estimates are based on production from 31 operated and 15 non-operated wells.

The existing PDNP estimates are based on projected production from 2 operated and 2 non-operated wells. Contingent resources are estimated for areas outside of a producing well location. The 1C contingent resources are limited to any development unit that contains an existing TMS well which would have been considered as reserves had the development plan included such locations within the five-year development window.

The 2C and 3C considered all the remaining undeveloped net acreage within the core area but used different estimates of in-place volumes and recovery factors. No gas sales are assumed in the reserve estimates as all gas is presently consumed on the lease, however projected gas volumes are included in the contingent resource estimates. The following key factors contributed to the changes in contingent resource: All subsurface assumptions on in place volumes and recovery factors remained identical for both the YE2020 and the YE2021 resource estimates.

All undeveloped acreage was evaluated for contingent resource based on the decision not to consider a development plan. During 2021 Australis carried out strategically targeted leasing, to maintain control and footprint in the play, without necessarily simply maintaining an acreage position. The net resultant reduction was from 107,500 to ~98,000 net acres and this directly influences the contingent resource calculation.