Iconic Potential, Acknowledgement of Country

Indirect hydrocarbon indication surveys of SPA-89 highlighted three adjoining 3D GravMag leads (the “SPA-89 Trio”) with multiple indications of a pressured hydrocarbon accumulation in the subsurface below and total mean unrisked prospective resource recoverable of 5.0 BnBO or 3.1 BnOEB gas at a relatively shallow depth of 4,200 m (13,300 feet) for iconic economic potential - Indirect hydrocarbon indication surveys seek manifestations at the surface of the near vertical migration of microseepages from an active petroleum system (pressured hydrocarbon accumulation) in the subsurface below. With 80% of over 1,000 wells drilled with anindirect hydrocarbon indication discoveries, the SPA-89 Trio with total mean unrisked prospective resource recoverable of 5.0 BnBO or 3.1 BnOEB gasand 94% to 100% of as many as four indirect hydrocarbon indications are highly prospective.

Located onshore and at shallow depth, the SPA-89 Trio offer potential iconic extraordinary economics. Assuming peak production of 300,000 barrels per day per billion barrels of recoverable oil resource as forecast for the ConocoPhillips’ Alaska North Slope Willow project as well as ExxonMobil’s offshore Guyana production, peak daily production for 5.0 BnBO is 1.5 million barrels per day for multi-billions of gross revenue:

Brent USD 60 per barrel – annual gross revenue USD 32 billion
Brent USD 100 per barrel - annual gross revenue USD 54 billion.

That combination likely offers economics that markedly exceeds the recent deepwater and ultra-deepwater offshore discoveries of this magnitude that bear high drilling cost. For example, Galp Energia’s CEO in an October 2024 earnings call highlighted that well costs for offshore Namibia are “clearly falling down…so, our well costs are south of EUR 75 million (USD 83 million fx 1.1) per well”.

Wells drilled in the area of SPA-89feature massive reservoirs with excellent geophysical properties that can host multi-billions of barrels of prospective recoverable resource – A petrophysical study of the area of SPA-89 confirmed massive reservoirs with excellent geophysical properties. With that geology, a 2009 Ryder Scott independent evaluation of the hydrocarbon resource potential of an Officer Basin license covering the southern part of SPA-89 best (P50) estimate of recoverable resource for five formations was 32.3 billion barrels oil (“BnBO”) or 21.3 billion oil-equivalent barrels (“BnOEB”) gas.

Equally significant, a review of the depth to basement map of the Officer Basin area shows SPA-89 shares the same sediment thickness as wells to the west of SPA-89 where most hydrocarbon shows are seen.

Proprietary 3D GravMag mapping process that maps subsurface structures equivalent to 3D seismic subsurface mapping mapped one formation in 12 structures with total mean unrisked prospective oil resource recoverable of the 9.16 BnBO or 5.14 BnOEB gas - Processing of a recent dense grid gravity and magnetic survey of SPA-89 with Raphael’s proprietary 3D GravMag mapping process that maps subsurface structures equivalent to 3D seismic subsurface mapping with a depth resolution on the Z-axis as low as 50 meters (160 fe et), mapped the Hussar formation in 10 deeper structures and the Wahlgu formation in two shallower structures. Located in a tectonically quiescent area for structures with vast areas that coupled with the massive reservoirs seen in the wells in the area of SPA-89, yielded total mean unrisked prospective resource recoverable of 9.16 billion barrels oil or 5.14 oil-equivalent barrels gas.

Four deeper 3D GravMag leads with total mean unrisked prospective resource recoverable of 1.2 BnBO or 700 million oil-equivalent barrels (“MnOEB”) gas with 68% to 100% of potential indirect hydrocarbon indications located onshore likely offer compelling economics – Three 3D GravMag leads with total mean unrisked prospective resource recoverableof 850 million barrels of oil (“MnBO”) or 510 MnOEB gas with 72% to 100% of four indirect hydrocarbon indications at total depths of 5,200 meters to 5,500 meters (17,100 feet to 18,000 feet) offering high and promising prospectivity and likely compelling economics.

A fourth 3D GravMag lead with 68% of four indirect hydrocarbon indications with mean unrisked prospective resource recoverableof310 MnBO or 190 MnOEB gas at a total depth of 7,700 meters (25,300 feet) likely offers compelling economics as well.

Petrophysical Study of the Area Around SPA-89

The Officer Basin has an estimated sedimentary sequence of up to 10,000 meters (33,000 feet), although uplift and erosion has removed some of the sediments. In addition, a 2009 Ryder Scott independent evaluation of the hydrocarbon resource potential of Officer Basin licenses including one covering the southern part of SPA-89, noted that nearly all potential hydrocarbon reservoirs in the Officer Basin are fluvial or aeolian sandstones with secondary porosity enhancement and that many have oil or gas shows.

A geophysical study of five formations in eight wells drilled in the area of SPA-89 confirmed the presence of massive reservoirs with excellent geophysical properties:

Gross reservoirs - 111 meters to 890 meters (364 feet to 2,919 feet), average 376 meters (1,234 feet)
Net reservoirs - 5 meters to 344 meters (16 feet to 1,128 feet), average 170 meters (559 feet).

An Interactive Petrophysics & Techlog software study of the Kanpa and Hussar formations in four wells in the Yowalga sub-basin to the west of SPA-89 – Empress-1, Kanpa-1, Lungkarta-1 and Yowalga-3 - found porosity ranging from 13% to 37% for wells in the shallower area of the basin and 15% to 17% for wells in the deeper area of the basin while net to gross reservoir ranged from 27% to 60% for wells in the shallower area of the basin and 26% to 38% for wells in the deeper area of the basin.

In addition, a review of the depth to basement map of the Officer Basin area shows SPA-89 shares the same sediment thickness as the area of the Kanpa-1, Lennis-1, and the Yowalga and Browne wells where most hydrocarbon shows are seen.

Raphael Proprietary 3D GravMag Mapping of SPA-89

Afif Arbi, Raphael Exploration Manager and Chief Technology Officer, developed the 3D GravMag processing method that maps subsurface structures equivalent to 3D seismic subsurface mapping with a depth resolution on the Z-axis as low as 50 meters (160 feet). Chevron sponsored Mr. Arbi’s PhD research in the US based on his academic excellence.

Fortunately, a recent dense grid 400 meter (1,300 foot) gravity and magnetic survey of the area of SPA-89 was available to process. One formation in 12 structures was mapped with the Hussar formation mapped in 10 deeper structures and the Wahlgu formation in two shallow structures. With the benefit of massive reservoirs seen in wells in the area of SPA-89 and a tectonically quiescent area of the Officer Basin for vast areas, the structures have reservoir geometry that may host multi-billion barrels prospective resource recoverable as summarized below:

Areas – P50 areas ranging from 11 km2 (4.2 mile2) to 112 km2 (43 mile2) with eight SPA-89 structures with P50 areas greater than 50 km2 (19 mile2).
Gross reservoirs – gross reservoirs ranging from 100 meters (330 feet) to 1,200 meters (3,940 feet) including six SPA-89 gross reservoirs greater than 500 meters (1,640 feet).

Significantly, in addition to immense savings in terms of time and capital intensity, 3D GravMag mapping saved the significant disturbance footprint of a 3D seismic survey. For example, assuming 2.9 km of seismic source lines per km2, a survey of just 25% of the area of SPA-89 would incur the disturbance footprint of ~5,900 km (3,700 miles) of seismic source lines.

SPA-89 Unrisked Prospective Recoverable Resource Estimates

Mean unrisked prospective resource recoverable estimates for one formation in 12 3D GravMag mapped structures totals 9.16 BnBO or 5.14 BnOEB gas. Estimates by formation are as follows:

Hussar formation (10 deeper 3D GravMag leads)

Oil - mean 7.02 BnBO (P90 2.71 BnBO, P10 12.02 BnBO)
Gas - mean 5.14 BnOEB (P90 1.99 BnOEB, P10 8.89 BnOEB)

Wahlgu formation (2 shallower 3D GravMag leads)

Oil - mean 2.14 BnBO (P90 700 MnBO, P10 3.80 BnBO)
Gas - mean 830 MnOEB (P90 300 MnOEB, P10 1.48 BnOEB)

For a frame of reference, the unrisked estimates of the Ryder Scott 2009 independent evaluation of the hydrocarbon resource potential for five formations of a license covering the southern part of SPA-89 were:

Best (P50) - 32.3 BnBO or 21.3 BnOEB gas
Low (P90) - 17.0 BnBO or 11.8 BnOEB gas
High (P10) - 55.5 BnBO or 35.5 BnOEB gas

Indirect Hydrocarbon Indication Surveys

While past loose-grid 2D seismic drilling campaigns have confirmed Officer Basin hosts massive reservoirs with excellent geophysical properties and many oil and gas shows, they did not yield any commercial discoveries.

In addition to 3D GravMag mapping, as part of the initial phase of the Raphael MaxEx Direct exploration process that seeks, confirms and quantifies hydrocarbon indications by phase and depth, Raphael undertook four surveys of SPA-89 seeking indirect hydrocarbon indications, the manifestation at the surface of the near vertical migration of microseepages from an active petroleum system (pressured hydrocarbon accumulation) in the subsurface below.

With a presentation at the American Association of Petroleum Geologists 2017 International Conference reporting that 80% of 1,150 wells drilled with an indirect hydrocarbon indication (positive anomaly) were discoveries while only 11% of 1,371 wells drilled without an indirect hydrocarbon indication (negative anomaly) were discoveries, arguably indirect hydrocarbon indications are a “hydrocarbon treasure map”.

The four indirect hydrocarbon indication surveys of SPA-89 were:

ARAD Radiometric gamma anomalies – Raphael’s refinement of the processing and mapping of microseepage induced mutual divergence of uranium & potassium
- Delta Divergence – computer mapping of the magnitude (intensity) of the changes in the microseepage induced mutual divergence of uranium (U) and potassium (K)
- Cross-Profile – visual review of cross-profiles of uranium (U) and potassium (K) for mutual divergences in U & K
Clay and carbonate alterations – microseepage induced reducing environment prompts higher concentrations of clay minerals and carbonates
- Spectral analysis of satellite images identified areas with higher concentrations of clay & carbonates
Iron alterations – spectral analysis of satellite images highlighted iron alterations induced by the presence of acidic or reducing agents in hydrocarbon microseepage-bearing areas
- Ferrous iron (Fe2+) increase; and
- Ferric iron (Fe3+) decrease
Topographic highs - Long-term microseepage and hydrocarbon oxidation engender secondary cementation of shallow sediments and soil, likely making the terrain above them more resistant to erosion

With Raphael refined ARAD radiometric processing and mapping, ARAD radiometric gamma anomalies are the primary indirect hydrocarbon indication method with the three other methods corroborating ARAD radiometric processing.

In addition, Beach Energy drilled the Trigg Northwest-1, a 3D seismic prospect, that reached total depth in August 2023. Located outside of the southern edge of the ARAD potential zone, it encountered 6m of net pay. See South Erregulla ARAD Potential Zone for the well locations.

While the down-hole logs of South Erregulla-2, South Erregulla-3 and Trigg Northwest-1 were positive, South Erregulla-2 and 3 failed their flow tests with South Erregulla-2 producing gas and formation water to the surface while South Erregulla-3 failed to flow and Beach’s Trigg Northwest-1 had a stabilised gas flow rate of only 0.7 MMscfd and remains undeveloped.

These results demonstrate that indirect hydrocarbon indications, induced by the near vertical migration of microseepages from an active petroleum system (pressured hydrocarbon accumulation), provide indications of the area of one or more pressured oil and gas accumulations.

“Fade” of radiometric anomalies when a hydrocarbon accumulation loses its pressure - The Dongara area radiometric data was acquired after six shallower older fields had been heavily depleted (80 to 90 percent). With depleted reservoirs losing high pressure, lower pressure reduces and/or ends hydrocarbon microseeping causing gamma anomalies to “fade”.

The Dongara study demonstrated the “fade” of radiometric indirect hydrocarbon indications with five depleted fields producing no Targeting ARAD gamma anomalies and only the heavily depleted Dongara field producing a weak Targeting ARAD gamma anomaly with additional mapping studies confirming no gamma anomalies associated with the field.

Indirect hydrocarbon indications false negative risk - The Dongara area radiometric study also highlighted false negative risk of indirect hydrocarbon indications – absence of an indirect hydrocarbon accumulation associated with discovery. A Lockyer Deep discovery did not have an associated Targeting ARAD gamma anomaly while a Beharra Springs Deep discovery was drilled in the area of a data void.

The American Association of Petroleum Geologists 2017 International Conference presentation quantified the false negative risk reporting that 11% of 1,371 wells drilled without an indirect hydrocarbon indication (negative anomaly) were discoveries.

Mitigation of false negative risk – Significantly, Raphael mitigates false negative risk with EMAI (electromagnetic analogue induction) logging of structures with reservoir geometry that may host a significant hydrocarbon accumulation or other areas of interest. As reviewed in greater detail below, EMAI logging provides high resolution at-depth indications of fluids – oil, gas, water – and inferred permeability. Highly sensitive to the presence of hydrocarbons and a depth capacity of approximately 6,000 meters (20,000 feet), it is an excellent tool to mitigate false negative risk that compares favorably to drilling a well.

Cooper-Eromanga Basin South Australia Area Radiometric Study

In 2020, Raphael undertook a study of much of the South Australia area of the Cooper-Eromanga Basins that was heavily explored with extensive 2D and 3D seismic coverage and 1,598 study wells that had produced a total of approximately 1.3 BnOEB since the beginning of the study period in 1997. In addition, study area dry holes totalled only 99 wells.

Extensive well information enabled refinement of ARAD delta divergence algorithms to map high intensity ARAD radiometric “sweet spot” leads that captured 88% of production and 98% when the area of the sweet spot was extended for the root mean square error (RMSE) associated with numerical interpolation. Dry holes were reduced by 91%. Stellar outcomes in part due to refinement of ARAD algorithms to extensive well information.

See the September 2021 Calgary GeoConvention presentation for more details on the Cooper-Eromanga radiometric study.

And as demonstrated with the Dongara area radiometric study, the near vertical migration of microseepages provides an indication of the area of one or more pressured hydrocarbon accumulations in the subsurface below. In addition to being highly prospective, the areas of SPA-89 Trio indirect hydrocarbon indications are generally greater than the P50 area of the SPA-89 structures, suggesting potential P10 accumulations of possibly 8.9 BnBO or 5.4 BnOEB gas. See 3D GravMag Structure Map Concorde Top of Hussar and IHIs for the Concorde 3D structure map and the four associated indirect hydrocarbon indications. Notably, mean unrisked prospective resource recoverable for Concorde is 2.3 BnBO (P90 1.0 BnBO, P10 3.8 BnBO) or 1.4 BnOEB gas (P90 600 MnOEB, P10 2.3 BnOEB).

At an estimated total depth of ~4,200 meters (13,800 feet), the SPA-89 Trio with total mean unrisked prospective recoverable resource of 5.0 BnBO or 3.1 BnOEB gas and the area of indirect hydrocarbon indications suggesting unrisked P10 accumulation 8.9 BnBO or 5.4 BnOEB gas, the SPA-89 Trio offer potential iconic economics.

Dongara Area North Perth Basin Radiometric Studies

To validate the efficacy of radiometric indirect hydrocarbon indications Raphael undertook a radiometric survey of the Dongara area of a North Perth Basin deep gas play initiated with a discovery in 2014. That work led to Raphael’s ARAD radiometric studies, a refinement of processing and mapping of radiometric data. Raphael presented ARAD radiometric studies of the Dongara area at the June 2019 American Association Petroleum Geologists Hedberg conference and via video at the September 2021 Calgary GeoConvention.

Five North Perth discoveries have an associated Targeting ARAD radiometric anomaly including the 2014 discovery well and the other four discoveries anomalies mapped pre-drill. Briefly, Targeting ARADs are the gamma anomalies with highest divergences between U (uranium) and K (potassium) that if sitting atop or near a fault, a Targeting ARAD is an indication of an active migration pathway.

While the 2019 AAPG Hedberg presentation featured Targeting ARADs, the mapping for the 2021 Calgary GeocConvention presentation featured more prominent Targeting ARADs. See Raphael 2021 Calgary GeoConvention North Perth Targeting ARADs for the five Dongara area discoveries with an associated Targeting ARAD.

Targeting ARADs of three of the Dongara discoveries are very prominent while the West Erregulla Targeting ARAD is less prominent than the play opening Waitsia discovery and the subsequent North Erregulla Deep and Erregulla Deep discoveries. And the South Erregulla Targeting ARAD could easily be overlooked but still targeted a discovery.

For example, assuming 8.0 BnBO of recoverable oil resource, 90% of P10 recoverable oil estimate, and peak production at 300,000 barrels per day per billion barrels of recoverable oil resource, peak annual production is ~2.4 million barrels per day for annual gross revenue as follows:

Brent USD 60 per barrel –USD 52 billion,
Brent USD 100 per barrel - USD 86 billion.

Deeper 3D GravMag Leads with Promising to High Prospectivity - Another three 3D GravMag leads with total depths of 5,200 meters to 5,500 meters (17,100 feet to 18,000 feet) have promising to high prospectivity with 72% to 100% of as many as four indirect hydrocarbon indications. Located in the deeper area of the basin for porosity of 15% to 17% and net to gross reservoirs of 26% to 38% based on Interactive Petrophysics and Techlog software processing of well logs of wells in the deeper area of basin, mean unrisked prospective recoverable resource totals 850 MnBO (P90 300 MnBO, P10 1.40 BnBO) or 510 MnOEB gas (P90 200 MnOEB gas, P10 900 MnOEB gas).

A fourth 3D GravMag with an estimated total depth of 7,700 meters (25,300 feet) with promising prospectivity of 68% of potential indirect hydrocarbon indications has mean unrisked prospective recoverable resource of 310 MnBO (P90 100 MnBO, P10 500 MnBO) or 190 MnOEB gas (P90 80 MnOEB gas, P10 300 MnOEB gas).

In total, the four deeper 3D GravMag leads with promising and high prospectivity have mean unrisked prospective resource recoverable of 1.16 BnBO (P90 400 MnBO, P10 1.90 BnBO) or 700 MnOEB gas (P90 400 MnOEB gas, P10 1.20 BnOEB gas).

Including five 3D GravMag leads with lesser indications of prospectivity, mean unrisked prospective resource recoverable for one formation for SPA-89 totals 9.16 BnBO or 5.14 BnOEB gas. See Table of SPA-89 3D GravMag Leads Unrisked Recoverable Resource Estimates and Reservoir Geometry for details by 3D GravMag lead of mean unrisked recoverable resource estimate, percentage of potential indirect hydrocarbon indications (IHIs) and reservoir geometry.

Maturing 3D GravMag leads to prospects – While indirect hydrocarbon indication surveys of SPA-89 provide indications of the area of one or more pressured hydrocarbon accumulations, they do not provide the associated depth or hydrocarbon phase. To mature 3D GravMag leads to prospects, Raphael undertakes EMAI (electromagnetic analogue induction) logging of 3D GravMag structures, a high resolution magnetotelluric technique that extracts data imprinted on deeper penetrating lower frequency signals for analogue induction logs (AIL) with fluid indications – oil, gas, water – and inferred porosity and permeability from significant depth. Resolution of analogue induction logs is 2 to 3 meters (6 to 10 feet) down to a depth of approximately 6,000 meters (20,000 feet). See Analogue Induction Logs (AIL) - Oil Accumulations Including One with a Gas Cap for an illustration of analogue induction logs of two oil accumulations including one with a gas cap.

Using high resolution analogue induction logs, Raphael builds 3D reservoir models that enable refined resource estimates by hydrocarbon phase and depth. Notably, 3D EMAI reservoir models can be validated with passive soil gas studies over the area of a 3D EMAI reservoir model with the area and intensity of microseepages in the near surface correlated by hydrocarbon phase and intensity to the 3D EMAI reservoir model as well as structural conformance.

The outcome of the MaxEx Direct process is 3D prospects with resource estimates by hydrocarbon phase and associated depth that with likely one or more associated indirect hydrocarbon indications that alone have an 80% discovery rate, have a high chance of success.

EMAI Logging of Two Long Unmapped Potential Deep Gas Leads – SPA-89 has two potential long deep gas accumulations, one ~30 km by ~10 km (19 miles by 6 miles) and second one ~20 km by ~5 km (12 miles by 3 miles), with a radiometric gamma anomaly that conforms to the edges of a topographic high. These will likely be EMAI logged to better assess the prospectivity of the leads followed by 3D GravMag mapping of the leads if the EMAI logging results are positive.

Measure Twice, Cut Once - Applying the carpenter’s axiom of “measure twice, cut once” to oil and gas exploration, potential drilling locations are de-risked and high-graded with additional EMAI logging. With EMAI logging effectively logging an oversized bore hole of approximately 0.5% of depth, i.e., 10 meters (33 feet) at 2,000 meters depth and 20 meters (66 feet) at 4,000 meters, multiple locations around potential drilling locations are undertaken with high grading likely focused on seeking locations to optimize reservoir contact. Even extended reach wells can be de-risked and high-graded with EMAI logging of locations along the paths of potential laterals to optimize reservoir contact.

False Negative Risk Mitigation – As noted in the Dongara area radiometric survey section, a 2017 review of indirect hydrocarbon indication studies found that 11% of 1,371 wells drilled with a negative anomaly – no indirect hydrocarbon indication – were discoveries. Raphael can efficiently mitigate the implied 11% false negative risk with EMAI logging of 3D GravMag leads with significant reservoir geometry but little or no associated indirect hydrocarbon indications.

SPA-89 hosts four 3D GravMag structures with significant reservoir geometry but limited associated indirect hydrocarbon indications – Belle Deep South, Belle Shallow North, Belle Shallow South and Fortuna North – with total mean unrisked prospective resource recoverable of 2.98 BnBO or 1.39 BnOEB gas.

Efficiency of MaxEx Direct Exploration Process - All of the above can be accomplished for a tiny fraction of the cost of generating even loose grid 2D seismic prospects plus saves the significant disturbance footprint of a 3D seismic survey. Assuming ~3 km (1.9 miles) of seismic source lines per km2, a 3D seismic survey of just 25% of SPA-89 would incur ~5,900 km (3,700 miles) of seismic source lines.

Extended Reach Drilling

Extended reach drilling is a directional drilling technique to drill long horizontal sections relative to their vertical depth, allowing access to hydrocarbon reservoirs several km (miles) away from the surface drilling location. Extended reach drilling offers potential optimized resource recovery, reduced environmental footprint and enhanced operational efficiency. And as noted in the Measure Twice, Cut Once section, long laterals can be de-risked and high-graded with EMAI logging of locations along potential lateral paths.

The vast areas of the SPA-89 Trio and possibly other leads with promising prospectivity are likely candidates for extended reach drilling.

ConocoPhillips has successfully used extended reach drilling for its North Slope Alaska exploration. With 6,700 meter (22,000 foot) laterals, since 2016 ConocoPhillips has been able to explore an area of ~140 km2 (55 mile2) from a small 0.05 km2 (12 acre) pad. Assuming reduced onshore Australia rig capability, a 3,000 meter (9,800 feet) lateral could explore an area of ~48 km2 (18.5 mile2) such that the P50 areas of the four highly prospective 3D GravMag leads – Ambrosia North, Ambrosia South, Concorde and Evo North - with a P50 area of 284 km2 (110 mile2) could be explored with only eight drill pads with a total area of 0.40 km2 (96 acres).

And given an analysis by TGS, a global provider of advanced energy data and intelligence, finding longer laterals produced meaningful increases in PV-10 outcomes from accelerated initial production (see TGS Chart of Permian Basin Extended Reach Wells Production Curves), should Concorde and the other highly and promisingly prospective leads have P10 accumulations, after initial drilling of prospects with vertical wells to mature them to discoveries, the significant additional recoverable resource of a P10 discovery may support importing or building a rig with the capacity to drill longer laterals to more efficiently explore P10 accumulations. For example, an increase in lateral length from 3,000 meters (9,800 feet) to 4,500 meters (14,800 feet) increases the area of exploration by 33% from 48 km2 (18.5 mile2) to 64 km2 (24.7 mile2).

The substantial reduction in the surface disturbance of the Raphael MaxEx Direct process coupled with extended reach drilling offers the Traditional Owners the significant benefits of the iconic potential of SPA-89 while minimizing the impact on their lands, waterways and communities.

Acknowledgement of Country

We acknowledge Aboriginal and Torres Strait Islander peoples as the Traditional Custodians of this land, their enduring connection to the lands, waterways and communities and pay respects to Elders and leaders past, present and emerging.