3D Oil : 2020 Annual Report to Shareholders

3D Oil has strengthened its portfolio of high potential, frontier offshore exploration permits in Australia, while ensuring the progression of high-impact gas projects through arguably one of the best farmout deals in the last 15 years in Australia.

A farm down in equity of T/49-P permit (20%-owned), offshore Otway Basin, to ConocoPhillips provides the opportunity to realise a total prospective gas resource of 10TCF (Best Estimate).

Executive Chairman's Letter to shareholders

The 100%-owned WA- 527-P permit covers a large underexplored area with similar plays to the significant Dorado-1 hydrocarbon discovery in the Bedout Sub-basin.

The 50%-ownedVIC-P74 permit, offshore Gippsland Basin, is proximal to the largest oil discovery in Australia and under evaluation through the recent purchase of state-of-the-art reprocessing.

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If just for a moment we put the effects of Covid-19 on the global economy aside I can categorically state that 3D Oil has had its most positive year since the inception of the company.

Of course, virtually all facets of business have been affected by the tsunami which is Covid-19 and the oil and gas industry is no exception. In fact, prior to the outbreak a glut of oil globally had already significantly softened the oil price. Covid-19 drove global oil price below US$ 30 per bbl and resulted in some cases an inability to dispose of oil as global demand dropped by approximately 10%. Subsequently gas prices have fallen as a function of the linkage between oil price and long-term gas contracts - though we may have already passed the bottom for LNG prices as demand in SE Asia has recently risen driven by switching from coal to gas power generation.

The uncertainty created by Covid-19 shows little sign of abating. Second waves continue to strike countries globally. While major oil and gas companies slash budgets and staff levels. In the US we have witnessed the shale oil industry be decimated due to high costs of production, representing about 10% of global production, the withdrawal of capital from the industry and a number of high-profile shale company insolvencies. Global investment in exploration and development has dried up. Many projects in pre execution phase are now on ice with a 32% reduction in capex so far this year compared to last year.

In spite of this dramatic backdrop 3D Oil has managed to secure arguably the best farmout deal in Australia for over 15 years.

But more on this in moment.

Is there a silver lining to this crisis? Considering historical oil prices most oil price collapses are followed by a significant rebound within a relatively short time - but of course every oil crisis is different and no one has a crystal ball.

I am extremely confident that 3D Oil will not only survive this crisis but will shine on the other side of the pandemic.

Our farmout of T/49P has stunned many in the industry for a number of reasons. The deal itself is exceptional by any standard; it was executed in the middle of the Covid-19 crisis when most majors were slashing budgets; ConocoPhillips ('COP') had recently sold major assets in Western Australia and appeared to be retreating. The deal also confirmed that 3D Oil's optimism in relation to the gas potential of this permit

is also shared with one of the largest oil and gas companies in the world. Most importantly it underlines that 3D Oil's strategy is valid. It is also arguably unique in Australia with virtually no other junior explorers attempting to disrupt where the majors explore.

Let me remind you of the major terms of the deal. 3D Oil received $5 million cash payment, COP to acquire a minimum of 1600 sq km of 3D seismic at no expense to 3D Oil. Further, if COP decide to drill they will carry the first US$30 million of the well. At the time of writing this letter COP are in full swing to undertake acquisition of the 3D seismic in 2021 while undertaking some preparation for drilling in 2022. The cash payment is particularly relevant as it enables TDO to fund its activities while it develops further value creation opportunities and positions itself for further farmouts

The timing could not be better with the Federal Government's push for a gas led recovery at a time when gas production in this region is in serious decline. Production from the Gippsland Basin is currently in rapid decline while in the Otway Basin operators have deferred exploration drilling.

I have said this previously it is 3D Oil's belief that the T/49P permit is the last place on the east coast where large gas reserves can potentially be uncovered. There is nowhere else.

I am proud our team has put us in the box seat. 3D Oil is now being carried towards the drilling of an exploration well that could realise reserves of potentially more than 1 TCF gas and provide an answer to the southeast gas supply deficit. 3D Oil is unique being one of the few remaining junior oil and gas companies active offshore in Australia and providing the opportunity to be involved in large scale hydrocarbon discoveries.

The acquisition of the Gippsland Basin permit VIC/P74 was no accident. It fit perfectly into our strategy of getting in early where the majors play. Of course, however, we had to have an idea. The permit has been poorly explored in the past and forgotten for almost two decades despite being adjacent the largest oilfield in Australia - Kingfish, which has produced over a billion barrels of oil.

The permit was picked up with a minimal bid - purchase of reprocessed 3D seismic - and it contains the Omeo gas discovery!

3D Oil recently acquired the 3D reprocessed seismic data which we are now singularly focused on interpreting. It may be an early call but VIC/P74 is shaping up as significantly more prospective than we could have foreseen. We are very excited about what we are uncovering and intend to release Prospective Resources to the market as soon as possible. It must be remembered the commercial threshold within this area is relatively low due to its proximity to existing infrastructure.

It is significant that we have had a number of unsolicited approaches on VIC/P74 already.

The acquisition of WA-527P permit prior to the discovery of Dorado was a master stroke by our team - it wasn't an accident or luck. We reviewed the previous drilling results of the region and the Dorado prospect and again picked up the permit for a relatively low work program bid. The rest is history of course, with the Dorado-1 well uncovering the largest oil discovery in Australia in decades, in a newly discovered petroleum province.

It is now pleasing to see that the Dorado joint venture is proceeding with FEED for the development of the field despite the low oil prices. This gives an indication of the robustness of the project.

The experience of farming out T/49P has taught us that patience is paramount when dealing with the majors. The process can be extremely long. Just getting a major through the door of a junior explorer is a significant achievement in itself. Once on board all opportunities have to be ranked against all global opportunities and then pass internal gateways. This process rarely takes less than 12 months! But as seen from the deal on T/49P the wait can be worth it, even transformational. WA-527P is now the only entry point for new players to access the Dorado style play and this exciting new petroleum system.

We have an exciting year ahead at 3D Oil with the acquisition of 3D seismic surveys in the Otway Basin and Bedout Sub-basin respectively. The focus in both areas will be to locate highly prospective drilling targets.

I am extremely proud of my team at 3D Oil which has executed a brilliant farmout by any measure but in the middle of a global pandemic!

3D Oil has survived through tough times, which means that we can keep participating in these high risk, but high value projects for the long haul, therefore maximizing the potential return to shareholders.

On behalf of the Company, I thank the Board and the 3D Oil team for their endeavors and commitment over the last year. They are an integral part of realizing our ambition to become a significant Australian oil and gas producer. I would also like to acknowledge the important contribution and thank our recently retired board advisor Peter Willcox.

Noel Newell

Managing Director

WA/527-P, BEDOUT SUB-BASIN, OFFSHORE NORTHWEST SHELF

"The acquisition of WA/527-P demonstrates the ability for 3D Oil to recognize opportunity early and act ahead of our larger competitors."

Figure 1 - WA/527-P Location and

Sea Floor Bathymetry

Exploration permit WA/527-P is a large permit covering approximately 6,500km2 in the Bedout Sub-basin of the Northwest Shelf, approximately 80km north-east of the recent Dorado oil and gas condensate discovery (Carnarvon Petroleum 20%, Santos 80%).

The Bedout Sub-basin is an element of the Roebuck Basin located along the productive Northwest Shelf of Australia. Recent exploration results in adjacent acreages have proven 3D Oil's long held technical view that the region hosts a prolific petroleum system that until recently has been overlooked

by industry. The acquisition of WA/527-P demonstrates the ability for 3D Oil to recognize opportunity early and act ahead of our larger competitors.

Exploration in the basin began during the 1980s with the drilling of the Phoenix wells by BP Australia. Disappointing results caused a lack of subsequent exploration activity in the basin, until the Phoenix South and Roc wells were drilled between 2014 and 2019. Phoenix South 1 discovered a series of light oil zones, while Roc 1 & 2 and other Phoenix South wells all discovered gas-condensate within sands of the lower Triassic, Caley reservoir.

In July of 2018, the Santos (ASX: STO) led Joint Venture drilled Dorado-1 discovering 162 MMbbls of liquids and 748 Bcf of gas within multiple reservoir zones of the Lower Triassic. The high quality of these sands has been confirmed by the Dorado appraisal program. Flow testing at Dorado-3 drilled in September of 2019, recorded a maximum 48 mscf/day of gas and 4,500 bbl/day oil from the Baxter reservoir while testing from the Caley achieved up to

11,100 bbl/day oil and 21mcf/day associated gas (STO release, 8 October 2019). Flow rates from both intervals were constrained by surface equipment and are some of the best ever recorded on the Northwest Shelf of Australia. These are excellent results for reservoirs buried greater than 4000m. Importantly, Triassic targets within WA/527-P are likely to have up to 1000m less overburden than at Dorado and are therefore interpreted to host similar if not better reservoir potential.

The Santos led Joint Venture is currently in the stakeholder consultation phase of a development plan at Dorado. The proposed development will comprise a Well Head Platform (WHP) with a Floating Production, Storage and Offloading Facility (FPSO). Once completed, the development will establish the Bedout Sub-basin as one of Australia's newest producing petroleum provinces. 3D Oil is proud to have secured a 6,500km2 piece of what will be Australia's newest petroleum producing region.

Activities

Throughout 2019, 3D Oil conducted reprocessing of a series of legacy

2D seismic lines. Results support the interpretation of a series of erosional channel systems (Figure 2) that may represent trapping mechanisms for targets within the lower Triassic. These erosional systems are considered important to the play concept as a similar feature, filled with impermeable claystone is proven to provide the trap for the nearby Dorado discovery.

The balance of available 2D seismic in WA/527-P is sparse with mostly poor quality and it is difficult to fully map these channels or any associated targets. As such, the next stage in 3D Oil's exploration campaign includes acquisition and processing of modern 3D seismic data.

During the year 3D Oil received approval to acquire the Sauropod 3D Marine Seismic Survey (MSS). The Sauropod 3D program is planned for January - April inclusive of 2021 and will allow for acquisition of up to 3,447 km2 of 3D seismic data. This survey is an integral next step in the exploration strategy for the permit and will have multiple objectives, including;

--Delineation of any targets that are analogous to the Dorado discovery by virtue of trapping against the interpreted Triassic erosional channel systems in the southwest of the acreage,

--Maturation of Leads identified by 2D seismic including Salamander, Jaubert and Whaleback,

--Investigation of the potential Palaeozoic play interpreted to be operating in the eastern side of the acreage and,

--Identification of any prospects that are not imaged by the current 2D seismic data.

Figure 2 - Interpretation of reprocessed seismic line JN87-20, including a series of erosional channels within WA/527-P

Sauropod has been designed to provide modern, high resolution imaging allowing, technical staff to determine whether identified traps represent viable closures, and detect any additional targets hidden between available 2D data.

Even with social distancing restrictions imposed throughout 2020, 3D Oil has continued to host presentations for multiple interested Exploration & Production companies. 3D Oil has also begun a procurement process for a seismic vessel operator that is capable of acquiring the Sauropod 3D MSS within the constraints of the approved Environment Plan.

Prospectivity

Mesozoic Leads

3D Oil has identified a series of structures along the western side of the acreage which may host Triassic sands, similar to those encountered at Dorado and Roc. Trap types in the Triassic play include

a combination of conventional faulted anticlines and possible stratigraphic traps sealed by the mentioned erosional channel systems. Additional inversion and fault- bound targets within the Jurassic sections are also identified.

The largest of the Mesozoic leads include Whaleback and Salamader, with a Best Estimate Prospective Resource of 86 MMbbls and 190 MMbbls respectively. The Sauropod 3D MSS will allow 3D Oil to delineate the structural closure of these features more accurately, and thus update the prospective resource estimates.

Figure 4 - Proposed Location of Sauropod

3D MSS Full-Fold Acquisition Area

Palaeozoic Leads

3D Oil has identified the presence of at least six reef-like features that could form viable oil targets. These features range in size from 3-30km2. These are mostly identifiable within the eastern side of the acreage, within what is interpreted to be a section of an extensive Palaeozoic Barrier Reef System. This system is proven as an effective petroleum system by the Blina and Ungani oil fields in the onshore Canning Basin. The Sauropod 3D MSS will provide imaging for the largest of these features located in the north of the permit.

Table 1: WA/527-P Prospective Resource Estimate (MMbbls) Recoverable Oil (ASX ann. 26/2/18)

3D Oil holds 20% interest in the T/49P exploration permit, which covers 4,960km2 of the strategic offshore Otway Basin. The permit is located adjacent to the producing Thylacine and Geographe gas fields (100% owned by Beach Energy Limited (ASX: BPT)).

The Otway Basin covers an area of ~150,000km2 along the southern margin of Australia. The basin has been an important supplier of gas to the east coast since the 1980s, and the T49/P permit is optimally placed to contribute much needed additional resources to this market.

3D Oil management firmly believes that the south-east Australian gas market will be strong in coming years as existing gas production in both the Gippsland and Otway Basin decline. The National COVID-19 response Co-ordination Commission

has flagged the importance of securing additional natural gas supply to fuel industry recovery from the COVID-19 Pandemic.

In addition, the federal government Technology Roadmap discussion paper released on 21 May 2020 comments that gas will play an important role as the nation switches from coal fired power, and will also support the uptake of renewable energy by filling gaps in the grid where renewable energy generation is intermittent.

3D Oil recognized the potential for the shortfall in gas supply to south-east Australia as early as 2012, and as a result acquired the T49/P exploration permit in the Otway Basin. The wider industry now shares the view that the region contains significant yet-to-find gas. In August of 2019 Cooper Energy (ASX:COE) drilled Annie-1 resulting in the first offshore gas discovery in the Otway Basin in 11 years. In December of 2019, Cooper Energy and Mitsui Group took possession of the Minerva Gas Plant and announced a $37 Million investment with the intention of processing gas from

the Casino, Henry and Netherby fields (COE Release, 20 July 2020). Beach Energy plans to drill up to nine wells between December 2020 and March 2021. The first of these will be the Aritsan-1 exploration well, followed by a series of near-field and appraisal wells at Thylacine and Geographe. Yet another compelling indication of the importance of the Otway Basin is the entrance of ConocoPhillips Australia, by way of farm-in to 3D Oil's T49/P exploration permit.

The T49/P permit contains a number of structures prospective for gas within an area of 4,960 km2 and in water depths generally no greater than 100m. The north of the permit is covered by 974 km2 of modern 3D seismic, while the area to the south remains lightly explored and covered by a broad grid of 2D seismic data of varying vintage and quality. Only two early exploration wells have been drilled in the permit (in 1967 and 1970) on historic, widely spaced 2D seismic. In subsequent years the region was largely overlooked by the industry despite the proximity of the Thylacine and Geographe gas fields.

Activities

This year 3D Oil completed the farm-out of 80% interest in the T49/P exploration permit to ConocoPhillips Australia SH1 Pty Ltd ('COP'). The National Offshore Petroleum Titles Administrator (NOPTA), granted approval for the farmout on

9 June 2020. This transaction signifies an important step forward in 3D Oil's strategy to discover gas in South East Australia and provide resources to the local market.

3D Oil believes that COP are the ideal partner, with the resources and technical expertise required to competently progress the exploration campaign in T49/P.

Under the terms of the Joint Operating Agreement ('JOA'), COP now holds 80% interest in the permit and is operating. In

accordance with the Farm out Agreement ('FOA'), COP has transferred A$5m cash payment to 3D OIL in recognition of previous permit expenditure. According to the agreement, COP will now undertake the acquisition of a 3D seismic survey of not less than 1580 sq km within the Permit to which 3D OIL will make no financial contribution.

The survey is of paramount importance to the Joint Venture's overall exploration strategy as it will cover remaining leads in lightly explored central and southern sections of the T/49P acreage and will allow for the generation of a permit-wide prospect seriatim that will inform the best possible drilling location.

Upon completion of the 3D seismic program, COP may elect to drill an exploration well which will full-fill the current Year 6 work commitment. In the event COP elects to drill such exploration well, the Company will be carried for up to US$30 million in drilling costs after which it will contribute 20% of drilling costs in line with its interest in the Permit.

Prospectivity

3D Oil selected T49/P based on its unique position within the regional structural configuration of the Southern Otway Basin. The permit is located along the edge of a paleo-shelf break, which was the depositional focus of a series of thick progradational clino-forms throughout the last 35 Million Years. These clino-forms have resulted in rapid loading of the proven sources rocks in this section of the Otway Basin. 3D Oil believes that this mechanism for hydrocarbon generation is responsible for charging the largest offshore Otway Basin gas fields, Thylacine and Geographe and

is likely to contribute hydrocarbons to the Leads and Prospects of T49/P (Figure 5).

Flanagan Prospect

Flanagan is the permit's 'drill ready' prospect. The structure has a maximum aerial closure of approximately 80 sq km and is positioned adjacent to multiple source kitchens. It is defined by the Flanagan 3D survey acquired in 2014 and has a best estimate prospective resource

1.34 TCF (announced 27 July 2017). The Prospect is located in shallow water and is the permit's closest feature to existing infrastructure at Thylacine and Geographe.

The potential for gas in the Flanagan Prospect is supported by quantitative geophysical modelling, which indicates the presence of a Class III amplitude versus offset (AVO) anomaly. In the Otway Basin, this type of response is known to be indicative of gas bearing sands.

Seal Rocks Lead

One of the key objectives of the upcoming 3D seismic program is the Seal Rocks Lead, located in the South of the permit. In 2019 3D Oil completed reprocessing and interpretation of legacy 2D seismic. This data defined the presence of high amplitude zones, likely to represent good quality reservoir sands appearing to fit

a series of tilted fault-blocks. While the reprocessed 2D seismic has provided a more accurate understanding of the structure at Seal Rocks, 3D seismic data

is required to determine the true resource potential of the feature.

Table 2: T/49P Prospective Resource Estimate (TCF) Recoverable Gas (ASX ann. 27-Jul-17)

The estimated quantities of petroleum that may potentially be recovered by the application of a future development project(s) relate to undiscovered accumulations. These estimates have both an associated risk of discovery and a risk of development. Further exploration appraisal and evaluation is required to determine the existence of a significant quantity of potentially moveable hydrocarbons

Exploration Permit VIC/P57 is located in the northwest of the offshore Gippsland Basin. The permit is approximately 246km2 in size and located in shallow waters close to shore and proximal to existing infrastructure. The permit was renewed by 3D Oil and operating partner Carnarvon Hibiscus Pty Ltd (CHPL) in 2018 for further five-year tenure. As part of this process the Joint Venture relinquished non prospective graticular blocks and has retained the most valuable acreage.

3D Oil holds a 24.9% interest in the VIC/

P57. By arrangement with permit operator Carnarvon Hibiscus Pty Ltd (CHPL), 3D Oil Limited continues to carry out subsurface technical work for the permit on behalf of the Joint Venture.

The Gippsland Basin, with initial reserves estimated at 4 billion barrels of oil and

11.5 trillion cubic feet of gas, is Australia's most prolific oil and gas producing basin. Twenty-one oil and gas fields are on production with most of the hydrocarbons hosted by the world-class sandstones of the Latrobe Group.

The Gippsland Basin is considered extremely important for gas supply to south east Australia, however, production from the basin is in decline. This year ExxonMobil continued with their plan to bring the West Barracouta development online, while Cooper Energy has commenced commissioning of the Orbost Gas Plant with the intention of processing gas from the Sole Gas field. The Australian Energy Market Operator (AEMO) Gas Statement of Opportunities released

in March of 2020 suggests that current and contingent resources (such as West Barracouta and Sole) will be insufficient to offset existing decline. Between 2019 and 2020 ExxonMobil embarked on a new drilling campaign in an attempt to bolster supply. The campaign included the drilling of exploration wells Hairtail-1,Baldfish-1 and Sculpin-1, however, all failed to discover additional resources.

In September of 2019, ExxonMobil announced their intention to sell their stake in the Gippsland Basin assets, including their interest in the Longford Gas plant.

In August of 2020, Joint Venture partner BHP announced that they too intended to sell their non-operator assets. If successful, this sale will end a 50-year history of ExxonMobil and BHP exploring and producing in the Gippsland Basin.

3D Oil believes that there are significant resources remaining in the Gippsland Basin, with many plays including some within the lower Latrobe Group remaining underexplored. If there is to be secure supply of gas to the south-east Australia, innovative exploration that takes advantage of modern data to investigate previously overlooked opportunities is required.

This requires investment in new technology such as modern seismic acquisition and/ or reprocessing of existing data with a focus on enhancing imaging of the less understood, deeper levels of the Gippsland Basin. The 3D Oil/Hibiscus Joint Venture is leveraging new reprocessed seismic data to search for new prospects. The Joint Venture now has two exploration permits in the western Gippsland Basin that share a common exploration rationale.

"The Australian Energy Market Operator (AEMO) Gas Statement of Opportunities released in March of 2020 suggests that current and contingent resources (such as West Barracouta and Sole) will be insufficient to offset existing decline"

Activities

The Joint Venture has completed its technical evaluation in VIC/P57. The primary term of the current renewal period was designed to de-risk and high grade the prospect inventory and ultimately progress prospects to 'drill-ready' status.

Two drilling candidates have been identified in the permit including; Felix and Pointer. The Pointer Prospect is an AVO supported gas target, located close to shore and nearby infrastructure. It is well placed to supply gas to the east Australian market. The Felix Prospect is a low risk Oil & Gas prospect located between the Wirrah discovery and Moonfish field. Dexter has been confirmed as a strong Lead and represents valuable additional potential for the permit.

Since completion of the technical program, a farm-out campaign was initiated, and 3D Oil has hosted data rooms for numerous interested parties throughout the year. The low risk profile of Felix and the potential for Pointer to provide low-cost gas to the domestic market is recognized by industry.

Prospectivity

Felix Prospect

Felix Prospect is an inversion anticline (Figure 8) favourably situated between the Moonfish and Wirrah discoveries along the Seahorse Fault. The structure is highly likely to have access to charge from the same kitchen as the existing discoveries. The reservoir-seal configuration is well constrained by nearby wells and excellent reservoir seal pairs are anticipated across the L.balmei zone at Felix.

Since finalizing interpretation of the latest reprocessed seismic data, 3D Oil believes that it is now possible to understand the trapping mechanism at Felix with far greater accuracy. This provides a higher degree of certainty with respect to the prospective resource estimations for the prospect. The improved velocity model from the reprocessed data has helped to de-risk the presence of closure in the depth domain across the L.balmei zone and has assisted with determining the best drilling location at the Prospect.

Figure 9 - Arbitrary seismic line through Wirrah Discovery, Felix Prospect and Moonfish Field (Image courtesy of CGG Multiclient & New Ventures)

Pointer Prospect

The Pointer Prospect is a combination structural-stratigraphic gas prospect within the Upper L.balmei reservoir of the upper Latrobe Group. The prospect shows a clear rising amplitude with offset response,

a Class III AVO (Figure 9) which is likely to represent dry gas. Improved imaging has permitted high-resolution mapping of the fault architecture and has reduced uncertainty on the trapping mechanism, highlighting a conformance of amplitude with structure. Located proximal to existing infrastructure, within water depths of less than 40m, and a drilling depth of ~1600m, Pointer represents low-cost development for the domestic gas market.

Figure 10 - Pointer Prospect Amplitude

Anomaly (image courtesy of CGG Multiclient &

New Ventures)

Table 3: Total VIC/P57 Prospective Resources Estimate (MMbbls) Recoverable Oil (ASX ann. 27/7/17)

Table 4: Total VIC/P57 Prospective Resource Estimate (BCF) Recoverable Gas (ASX ann. 27/7/17)

Located in shallow waters of the offshore Gippsland Basin, VIC/P74 was awarded to 3D Oil on 26 July 2019 by the NOPTA. The permit covers 1,006 km2 and is situated on the southern flank of the Gippsland Basin, where it straddles the boundary of the Southern Terrace and the Central Deep.

The permit includes the Omeo Gas- condensate discovery and is located adjacent to the giant, world class Kingfish Oil Field, the largest oil field ever discovered in Australia. To date, Kingfish Field has produced over one billion barrels of oil from the classic Top of Latrobe play. Bream Field is also located adjacent to VIC/P74, a large oil and gas discovery also producing from the Top of Latrobe play, with additional columns throughout the deeper Latrobe Group.

As with VIC/P57, exploration of this region has been hampered by velocity anomalies in shallow overburden causing limitations to seismic imagery. Exploration drilling post-mortems suggests that several of the wells in permit have failed as a result of this issue.

As evidenced in VIC/P57, recent advances in reprocessing techniques have made significant improvements in relation to this technical limitation. The rationale for the acquisition of VIC/P74 was based on anticipated uplift in 3D imaging and velocity data given the availability of CGG 3D ReGeneration Reprocessing over the area, as well as the potential for significant un-drilled traps and the local prolific petroleum system.

Farmout to Hibiscus

In October 2019, 3D Oil announced that Carnarvon Hibiscus Pty Ltd ('CHPL'), an indirect wholly owned subsidiary of Hibiscus Petroleum Berhad, elected to enter into a joint venture agreement by acquiring a 50% interest in the permit.

During July of 2020, NOPTA approved the Assignment Agreement between 3D OIL and CHPL which created the right for the two companies to enter into a Joint Operating Agreement (JOA). 3D OIL has since executed a Joint JOA with CHPL and is currently awaiting approval of this document from NOPTA. Under the terms of the agreement, 3D Oil will remain as Operator and retain 50% equity in the permit.

3D OIL is pleased to further strengthen its partnership with Hibiscus. The Joint Venture now has significant acreage holding in the Western Gippsland Basin.

Activities

The primary work programme (Years 1-3) is fully funded and requires the development of an exploration database, purchase

of 905km2 of the CGG Gippsland 3D ReGeneration Reprocessing, and a range of geology and geophysics (G&G) studies aimed at adding to the Gippsland Joint Venture's portfolio of leads and prospects.

3D Oil's well database has been extended to include the local VIC/P74 area, allowing the construction of a seamless stratigraphic framework between VIC/P57 and VIC/P74, as well as an improved understanding of the local distribution of hydrocarbon shows and discoveries. This has included an in-house petrophysical assessment of the Omeo wells to aid in the development of a geostatistical model for the Omeo gas-condensate discovery, and subsequent volumetric assessment.

Geochemistry data has been consolidated and interrogated to determine local source rock candidates. Whole oil and cuttings geochemistry datasets from the Omeo wells indicate that hydrocarbons have migrated into the permit from a thermally mature source rock that is likely to contribute hydrocarbon to other targets in the permit.

Omeo hydrocarbon reservoirs are located within the Golden Beach Sub-Group, however, most Golden Beach well penetrations are located on the flank of the Northern Terrace. Hence, a regional assessment of formation tops and reservoir properties has better informed the

likely depositional settings and reservoir properties to be expected at any Golden Beach leads identified from future mapping of the CGG 3D reprocessing.

In August of 2020, the Joint Venture licensed 1,004 km2 of the CGG 3D ReGeneration Reprocessing, fulfilling a major work commitment of the primary term. Data includes full and offsets stacks, gathers and velocity cube. The next major phase of the VIC/P74 work programme will comprise the detailed interpretation of the seismic, including AVO screening and the identification of leads and prospects.

As anticipated, the state-of-the-art CGG reprocessing has yielded a significant uplift in data quality, especially across the deeper Latrobe Group stratigraphy. Most important to the strategy of the permit, the Joint Venture now has excellent constraint on velocity inversions across the shallow overburden, permitting increasingly accurate depth conversions. A range of depth conversion techniques and comprehensive sensitivity analysis will be conducted after the completion of the seismic interpretation.

The Directors present their report, together with the financial statements, on the consolidated entity (referred to hereafter as the 'Consolidated Entity') consisting

of 3D Oil Limited (referred to hereafter as the 'Company' or 'parent entity') and the entities it controlled at the end of, or during, the year ended 30 June 2020.

Directors

The following persons were Directors of 3D Oil Limited during the whole of the financial year and up to the date of this report, unless otherwise stated:

Mr Noel Newell

Mr Ian Tchacos

Mr Leo De Maria

Principal activities

During the financial year the principal continuing activities of the Company consisted of exploration and development of upstream oil and gas assets.

Dividends

There were no dividends paid or declared during the current or previous financial year.

The Consolidated Entity does not have franking credits available for subsequent financial years.

Review of operations

The loss for the Consolidated Entity after providing for income tax amounted to $3,006,065 (30 June 2019: $1,089,254).

Refer to the detailed Review of Operations preceding this Directors' Report.

Financial Position

The net assets decreased by $3,000,200 to $8,742,543 at 30 June 2020 (30 June 2019: $11,742,743). During the period the Consolidated Entity spent a net amount after reimbursements of $726,453 (2019: $880,967) on exploration, mainly in relation to WA/527P and VIC/P74 during the year. Exploration assets at 30 June 2020 were net of $5,000,000, received in relation to T/49P for the completion of Farm-out Agreement with Conoco Phillips. Following a review by the Directors and management, the book value of VIC/P57 was written down to Nil as at 30 June 2020, reflecting the estimated future economic benefits expected to be derived from this area of interest.

The working capital position as at 30 June 2020 of the Consolidated Entity results in an excess of current assets over current liabilities of $4,033,946 (30 June 2019: $903,047). The Consolidated Entity made a loss after tax of $3,006,065 during

the financial year (2019 loss: $1,089,254) and had net operating cash outflows of $980,209 (2019: $958,034). The cash balances, including term deposits, as at 30 June 2020 was $5,170,768 (2019: $1,934,458).

Based on the above the Directors believe the Company is in a stable position to continue to pursue its current operations.

Significant changes in the state of affairs

On 26 July 2019, the Company announced that it was awarded the VIC/P74 permit in the offshore Gippsland Basin. The permit covers approximately 1,006km2 and the primary work programme is modest and largely consists of purchase of reprocessed 3D seismic data.

On 4 October 2019, the Company and Hibiscus Petroleum Berhad entered into a farm-out arrangement in relation to VIC/P74. The Company will remain as operator with 50% equity when a Joint Operating Agreement (JOA) is signed by both parties and required government approvals.

On 18 December 2019, the Company announced that its wholly owned subsidiary, 3D Oil T49P Pty Ltd had executed a Farm-out Agreement ('FOA') with ConocoPhillips Australia SH1 Pty Ltd ('ConocoPhillips Australia') in relation

to the offshore Tasmanian Permit T/49P. ConocoPhillips Australia have taken operatorship of T/49P and were transferred an 80% interest in the permit at completion of the Farm-out. In exchange for the transfer:

--3D Oil received a A$5m cash payment in recognition of previous permit expenditure;

--ConocoPhillips Australia will acquire at least 1,580km2 of 3D seismic survey in T/49P at no cost to 3D Oil; and

--ConocoPhillips Australia may elect to drill an exploration well in which it will carry up to the first US$30 million of costs, after which 3D Oil will contribute 20% of costs in line with its interest in the permit.

On 1 April 2020, the Company announced that it had been granted a 21-month Suspension and Extension by the National Offshore Petroleum Titles Administrator ('NOPTA') for the offshore Bedout Sub-basin permit WA-527-P. This now provides 3D Oil until the 28 December 2021 to acquire and process a minimum of 510 km2 of 3D seismic data.

There were no other significant changes in the state of affairs of the Consolidated Entity during the financial year.

Matters subsequent to the end of the financial year

On 14 July 2020, the Company announced that it has been awarded the necessary environmental approvals from the Commonwealth Statuary National Agency, NOPSEMA, to acquire the Sauropod

3D Marine Seismic Survey (MSS) within 100% owned WA-527-P of the Offshore Roebuck Basin.

No other matter or circumstance has arisen since 30 June 2020 that has significantly affected, or may significantly affect

the Consolidated Entity's operations, the results of those operations, or the Consolidated Entity's state of affairs in future financial years.

Likely developments and expected results of operations

The Consolidated Entity will continue to pursue its exploration interest in

--VIC/P57 and VIC/P74 in partnership with Carnarvon Hibiscus Pty Ltd;

--T/49P in partnership with Conoco Phillips Australia;

--WA-527-P in the Roebuck Basin of Western Australia.

Environmental regulation

The Consolidated Entity holds participating interests in a number of oil and gas areas. The various authorities granting such tenements require the licence holder to comply with the terms of the grant of the licence and all directions given to it under those terms of the licence. There have been no known breaches of the tenement conditions, and no such breaches have been notified by any government agencies during the year ended 30 June 2020.

Information on Directors

Mr Noel Newell

Executive Chairman

Qualifications

B App Sc (App Geol)

Experience and expertise

Noel Newell holds a Bachelor of Applied Science and has over 25 years' experience in the oil and gas industry, with 20 years of this time with BHP Billiton and Petrofina. With these companies Mr Newell has been technically involved in exploration of areas around the globe, particularly South East Asia and all major Australian offshore basins. Prior to leaving BHP Billiton in 2002, Mr Newell was Principal Geologist working within the Southern Margin Company

and primarily responsible for exploration within the Gippsland Basin. Mr Newell has a number of technical publications and has co-authored Best Paper and runner up Best Paper at the Australian Petroleum Production & Exploration Association conference and Best Paper at the Western Australian Basins Symposium. Mr Newell is the founder of 3D Oil. Immediately prior to starting 3D Oil, Mr Newell was a technical advisor to Nexus Energy Limited and was directly involved in their move to explore in the offshore of the Gippsland Basin.

Other current directorships

None

Former directorships (last 3 years)

None

Special responsibilities

None

Interests in shares

44,192,229 ordinary fully paid shares.

Interests in options

None

Mr Leo De Maria

Non-Executive Director

Experience and expertise

Leo De Maria is a Chartered Accountant with extensive experience in company management, financial management, mergers and acquisitions and risk management.

Other current directorships

None

Former directorships (last 3 years)

None

Special responsibilities

Chairman of Audit Committee and Remuneration and Nomination Committee

Interests in shares

650,070 ordinary fully paid shares.

Interests in options

None

Mr Ian Tchacos

Non-Executive Director

Experience and expertise

Ian Tchacos is an oil and gas professional with over 30 years international experience in corporate development and strategy, mergers and acquisitions, petroleum exploration, development and production operations, decision analysis, commercial negotiation, oil and gas marketing and energy finance. He has

a proven management track record in a range of international energy company environments.

Other current directorships

ADX Energy Ltd

Former directorships (last 3 years)

Xstate Resources Limited (resigned on 26 November 2019)

Special responsibilities

Member of Audit Committee and Member

of Remuneration and Nomination

Committee

Interests in shares

428,500 ordinary fully paid shares

Interests in options

None

Company secretaries

Melanie Leydin

BBus (Acc. Corp Law) CA FGIA

Joint Company Secretary

Melanie Leydin holds a Bachelor of Business majoring in Accounting and Corporate Law. She is a member of the Institute of Chartered Accountants, Fellow of the Governance Institute of Australia and is a Registered Company Auditor. She graduated from Swinburne University in 1997, became a Chartered Accountant

in 1999 and since February 2000 has been the principal of Leydin Freyer. The practice provides outsourced company secretarial and accounting services to public and private companies across a host of industries including but not limited to the Resources, technology, bioscience, biotechnology and health sectors.

Melanie has over 25 years' experience in the accounting profession and over 15 years as a Company Secretary. She has extensive experience in relation to public company responsibilities, including ASX and ASIC compliance, control and implementation of corporate governance, statutory financial reporting, reorganisation of Companies and shareholder relations.

Mr Stefan Ross

Joint Company Secretary

Mr Ross has over 10 years of experience in accounting and secretarial services for ASX Listed companies. His extensive experience includes ASX compliance, corporate governance control and implementation, statutory financial reporting and Board and secretarial support.

'Other current directorships' quoted above are current directorships for listed entities only and excludes directorships in all other types of entities, unless otherwise stated.

'Former directorships (in the last 3 years)' quoted above are directorships held in the last 3 years for listed entities only and excludes directorships in all other types of entities, unless otherwise stated.

Remuneration report (audited)

The remuneration report, which has been audited, outlines the director and executive remuneration arrangements for the Company, in accordance with the requirements of the Corporations Act 2001 and its Regulations.

Key management personnel are those persons having authority and responsibility for planning, directing and controlling the activities of the entity, directly or indirectly, including all directors.

The remuneration report is set out under the following main headings:

--Principles used to determine the nature and amount of remuneration

--Details of remuneration --Service agreements --Share-based compensation --Additional information

--Additional disclosures relating to key management personnel

Principles used to determine the nature and amount of remuneration

The objective of the Consolidated Entity's executive reward framework is to ensure reward for performance is competitive and appropriate for the results delivered. The framework aligns executive reward with the achievement of strategic objectives and the creation of value for shareholders, and conforms with the market best practice for delivery of reward. The Board of Directors ('the Board') ensures that executive reward satisfies the following key criteria for good reward governance practices:

--competitiveness and reasonableness --acceptability to shareholders --alignment of executive compensation --transparency

The Board is responsible for determining and reviewing remuneration arrangements for its directors and executives. The performance of the Consolidated Entity and the Company depends on the quality of its directors and executives. The remuneration philosophy is to attract, motivate and retain high performance and high quality personnel.

The Board has structured an executive remuneration framework that is market competitive and complementary to the reward strategy of the Consolidated Entity.

The reward framework is designed to align executive reward to shareholders' interests. The Board have considered that it should seek to enhance shareholders' interests by:

--focusing on sustained growth in shareholder wealth, consisting of dividends and growth in share price, and delivering constant or increasing return on assets as well as focusing the executive on key non-financial drivers of value

--attracting and retaining high calibre executives

Additionally, the reward framework should seek to enhance executives' interests by:

--rewarding capability and experience

--reflecting competitive reward for contribution to growth in shareholder wealth

--providing a clear structure for earning rewards

In accordance with best practice corporate governance, the structure of non-executive director and executive director remuneration is separate.

Non-executive directors remuneration

Fees and payments to non-executive directors reflect the demands which are made on, and the responsibilities of, the directors. Non-executive directors fees and payments are reviewed annually by the Board. The chairman's fees are determined independently to the fees of other non-executive directors based on comparative roles in the external market. The chairman is not present at any discussions relating to determination of his/her own remuneration. Non-executive directors do not receive share options or other incentives.

ASX listing rules requires that the aggregate non-executive directors remuneration shall be determined periodically by a general meeting. The most recent determination was at the Annual General Meeting held on 21 November 2012, where the shareholders approved an aggregate remuneration of $400,000.

Executive remuneration

The Consolidated Entity aims to reward executives with a level and mix of remuneration based on their position and responsibility, which are both fixed.

The executive remuneration and reward framework have three components:

--base pay and non-monetary benefits --share-based payments

--other remuneration such as superannuation and long service leave

The combination of these comprises the executive's total remuneration.

Fixed remuneration, consisting of base salary, superannuation and non-monetary benefits, are reviewed annually by the Board, based on individual and business unit performance, the overall performance of the Company and comparable market remunerations.

Executives can receive their fixed remuneration in the form of cash or other fringe benefits (for example motor vehicle benefits) where it does not create any additional costs to the Company and adds additional value to the executive.

All Executives are eligible to receive a base salary (which is based on factors such as experience and comparable industry information) or consulting fee. The Board reviews the Executive Chairman's remuneration package, and the Executive Chairman reviews the senior Executives' remuneration packages annually by reference to the Consolidated Entity's performance, executive performance and comparable information within the industry.

The performance of Executives is measured against criteria agreed annually with each executive and is based predominantly on the overall success of the Consolidated Entity in achieving its broader corporate goals. Bonuses and incentives are linked to predetermined performance criteria. The Board may, however, exercise its discretion in relation to approving incentives, bonuses, and options, and can require changes

to the Executive's remuneration. This policy is designed to attract the highest calibre of Executives and reward them for performance that results in long-term growth in shareholder wealth.

All remuneration paid to Directors and Executives is valued at the cost to the Consolidated Entity and expensed. Options are valued using the Black-Scholes or Binomial methodology.

The long-term incentives ('LTI') includes long service leave and share-based payments. Shares and or options are awarded to executives on the discretion of the Board based on long-term incentive measures.

Consolidated Entity performance and link to remuneration

Remuneration packages do not include performance-based components. An individual member of staff's performance is assessed by reference to their contribution to the Company's overall achievements. The intention of this program is to facilitate goal congruence between Executives with that of the business and shareholders. Generally, the executive's remuneration is tied to the Consolidated Entity's successful achievement of certain key milestones as they relate to its operating activities.

Voting and comments made at the Company's 11 November 2019 Annual General Meeting ('AGM')

The Company received 91.78% of 'for' votes in relation to its remuneration report for the year ended 30 June 2019. The Company did not receive any specific feedback at the AGM regarding its remuneration practices.

Details of remuneration Amounts of remuneration

Details of the remuneration of key management personnel of the Consolidated Entity are set out in the following tables.

Details of the remuneration of the directors and other key management personnel (defined as those who have the authority and responsibility for planning, directing and controlling the major activities of the company) of the company are set out in the following tables.

Service agreements

Remuneration and other terms of employment for key management personnel are formalised in service agreements. Details of these agreements are as follows:

Mr N Newell

Executive Chairman

Agreement commenced

1 November 2006

Details

1. Mr Newell may resign from his position and thus terminate this contract by giving 6 months written notice.
2. The Company may terminate this employment agreement by providing 6 months written notice.
3. The Company may terminate the contract at any time without notice if serious misconduct has occurred. Where termination with cause occurs, Mr Newell is only entitled to that portion of remuneration which is fixed, and only up to the date of termination.
4. On termination of the agreement, Mr Newell will be entitled to be paid those outstanding amount owing to him up until the Termination date.

Mr Ian Tchacos

Non-Executive Director

Agreement commenced

14 October 2016

Details

1. Mr Tchacos may resign from his position and thus terminate this contract by giving 3 months written notice.
2. The Company may terminate this employment agreement by providing 3 months written notice.
3. The Company may terminate the contract at any time without notice if serious misconduct has occurred. Where termination with cause occurs, Mr Tchacos is only entitled to that portion of remuneration which is fixed, and only up the date of termination.
4. On termination of the agreement, Mr Tchacos will be entitled to be paid those outstanding amounts owing to him up until the Termination date.

Mr Leo De Maria

Non-Executive Director

Agreement commenced

30 September 2014

Details

1. Mr De Maria may resign from his position and thus terminate this contract by giving 3 months written notice.
2. The Company may terminate this employment agreement by providing 3 months written notice.
3. The Company may terminate the contract at any time without notice if serious misconduct has occurred. Where termination with cause occurs, Mr De Maria is only entitled to that portion of remuneration, which is fixed, and only up the date of termination.
4. On termination of the agreement,
   Mr De Maria will be entitled to be paid those outstanding amounts owing to his up until the Termination date.

Key management personnel have no entitlement to termination payments in the event of removal for misconduct.

Share-based compensation Issue of shares

The Company issued nil (2019: 1,552,072) shares to directors and key management personnel as part of compensation during the year ended 30 June 2020.

Options

There were no options over ordinary shares granted to or vested by Directors and other key management personnel as part of compensation during the year ended 30 June 2020 (2019: Nil).

Performance rights

There were no performance rights over ordinary shares issued to Directors and other key management personnel as part of compensation that were outstanding as at 30 June 2020 (2019: Nil).

Shares under option

There were no unissued ordinary shares of 3D Oil Limited under option outstanding at the date of this report.

Shares under performance rights

There were no unissued ordinary shares of 3D Oil Limited under performance rights outstanding at the date of this report.

Shares issued on the exercise of options

There were no ordinary shares of 3D Oil Limited issued on the exercise of options during the year ended 30 June 2020 and up to the date of this report.

Shares issued on the exercise of performance rights

There were no ordinary shares of

3D Oil Limited issued on the exercise of performance rights during the year ended 30 June 2020.

Indemnity and insurance of officers

The Consolidated Entity has indemnified the directors of the Company for costs incurred, in their capacity as a director, for which they may be held personally liable, except where there is a lack of good faith.

During the financial year, the Company paid a premium in respect of a contract to insure the directors of the Company against a liability to the extent permitted by the Corporations Act 2001. The contract of insurance prohibits disclosure of the nature of liability and the amount of the premium.

Indemnity and insurance of auditor

The Company has not otherwise, during or since the financial year, indemnified or agreed to indemnify the auditor of the Company or any related entity against a liability incurred by the auditor.

During the financial year, the Company has not paid a premium in respect of a contract to insure the auditor of the Company or any related entity.

Proceedings on behalf of the Company

No person has applied to the Court under section 237 of the Corporations Act 2001 for leave to bring proceedings on behalf of the Company, or to intervene in any proceedings to which the Company

is a party for the purpose of taking responsibility on behalf of the Company for all or part of those proceedings.

Non-audit services

There were no non-audit services provided during the financial year by the auditor.

Officers of the Company who are former partners of Grant Thornton Audit Pty Ltd

There are no officers of the Company who are former partners of Grant Thornton Audit Pty Ltd.

Auditor's independence declaration

A copy of the auditor's independence declaration as required under section 307C of the Corporations Act 2001 is set out immediately after this Directors' report.

Auditor

Grant Thornton Audit Pty Ltd continues in office in accordance with section 327 of the Corporations Act 2001.

Rounding of amounts

3D Oil Limited is a type of Company that is referred to in ASIC Corporations (Rounding in Financial/Directors' Reports) Instrument 2016/191 and therefore the amounts contained in this report and in the financial report have been rounded to the nearest dollar.

This report is made in accordance with a resolution of Directors, pursuant to section 298(2)(a) of the Corporations Act 2001.

On behalf of the Directors

Noel Newell

Executive Chairman

24 September 2020

Melbourne

Note 1. General information

The financial statements cover 3D Oil Limited as a consolidated entity consisting of 3D Oil Limited and the entities it controlled at the end of, or during, the year. The financial statements are presented in Australian dollars, which is 3D Oil Limited's functional and presentation currency.

3D Oil Limited is a listed public company limited by shares, incorporated and domiciled in Australia. Its registered office and principal place of business is:

Level 18

41 Exhibition Street

Melbourne VIC 3000

A description of the nature of the Consolidated Entity's operations and its principal activities are included in the Directors' report, which is not part of the financial statements.

The financial statements were authorised for issue, in accordance with a resolution of Directors, on 24 September 2020. The Directors have the power to amend and reissue the financial statements.

Note 2. Significant accounting policies

The principal accounting policies adopted in the preparation of the financial statements are set out either in the respective notes or below. These policies have been consistently applied to all the years presented, unless otherwise stated.

New or amended Accounting Standards and Interpretations adopted

The Consolidated Entity has adopted all of the new or amended Accounting Standards and Interpretations issued by the Australian Accounting Standards Board ('AASB') that are mandatory for the current reporting period.

Any new or amended Accounting Standards or Interpretations that are not yet mandatory have not been early adopted.

The adoption of these Accounting Standards and Interpretations did not have

any significant impact on the financial performance or position of the Consolidated Entity. The following Accounting Standards and Interpretations are most relevant to the Consolidated Entity:

Interpretation 23 Uncertainty over Income Tax Treatments

Interpretation 23 requires the assessment of whether the effect of uncertainty over income tax treatments should be included in the determination of taxable profit (tax loss), tax bases, unused tax losses, unused tax credits and tax rates. The Interpretation outlines the requirements to determine whether an entity considers uncertain tax treatments separately, the assumptions an entity makes about the examination

of tax treatments by taxation authorities, how an entity determines taxable profit (tax loss), tax bases, unused tax losses, unused tax credits and tax rates and how an entity considers changes in facts and circumstances.

The Company has adopted Interpretation 23 from 1 July 2019, based on an assessment of whether it is 'probable' that a taxation authority will accept an uncertain tax treatment. This assessment takes

into account that for certain jurisdictions in which the Company operates, a local tax authority may seek to open a company's books as far back as inception of the Company. Where it is probable, the Company has determined tax balances consistently with the tax treatment used or planned to be used in its income tax filings. Where the Company has determined that it is not probable that the taxation authority will accept an uncertain tax treatment, the most likely amount or the expected value has been used in determining taxable balances (depending on which method is expected to better predict the resolution of the uncertainty). There has been no impact from the adoption of Interpretation 23 in this reporting period.

AASB 16 Leases

The Consolidated Entity has adopted AASB 16 from 1 July 2019. The standard replaces AASB 117 'Leases' and for lessees eliminates the classifications of operating leases and finance leases. Except for short-term leases and leases of low-value assets, right-of-use assets and corresponding lease liabilities are recognised in the statement of financial position. Straight-line operating lease expense recognition is replaced with a depreciation charge for the right-of-use assets (included in operating costs) and an interest expense on the recognised lease

liabilities (included in finance costs). In the earlier periods of the lease, the expenses associated with the lease under AASB 16 will be higher when compared to lease expenses under AASB 117. However, EBITDA (Earnings Before Interest, Tax, Depreciation and Amortisation) results improve as

the operating expense is now replaced by interest expense and depreciation in profit or loss. For classification within the statement of cash flows, the interest portion is disclosed in operating activities and the principal portion of the lease payments are separately disclosed in financing activities. For lessor accounting, the standard does not substantially change how a lessor accounts for leases.

Other accounting pronouncements which have become effective from 1 July 2019 and have therefore been adopted have not had a significant impact on the Group's financial results or position.

Going concern

The financial report has been prepared on the going concern basis, which assumes continuity of normal business activities and the realisation of assets and the settlement of liabilities in the ordinary course of business.

The working capital position as at

30 June 2020 of the Consolidated Entity results in an excess of current assets over current liabilities of $4,023,321 (30 June 2019: $903,047). The Consolidated Entity made a loss after tax of $3,006,065 during the financial year (2019 loss: $1,089,254) and had net operating cash outflows of $980,209 (2019: $958,034). The cash balances, including term deposits, as

at 30 June 2020 was $5,170,768 (2019: $1,934,458). The continuing viability of the Consolidated Entity and its ability to continue as a going concern is dependent upon the Consolidated Entity being successful in its continuing efforts in exploration projects and accessing additional sources of capital to meet the commitments as and when required. To meet the Company's funding requirements as and when they fall due the Group will need to take appropriate steps, including a combination of:

--Raising capital by one of or a combination of the following: placement of shares, rights issue, share purchase plan, etc;

--Meeting its obligations by either farm-out or partial sale of the Group's exploration interests;

--Subject to negotiation and approval, minimum work requirements may be varied or suspended, and/or permits may be surrendered or cancelled; or

--Other avenues that may be available to the Group.

In March 2020, the World Health Organization declared the outbreak of a novel coronavirus (COVID-19) as a pandemic, which continues to spread globally as well as in Australia. The spread of COVID-19 has caused significant volatility in Australian and international markets. There is a significant uncertainty around the breadth and duration of business disruptions related to COVID-19 and therefore the Company has taken precautionary measures by temporarily closing the Company's office and having arranged for its employees to work remotely, as well

as minimising non-critical activities and curtailing travel. At the date of this report, the impact of these measures is not expected to significantly impact the completion of the current work being undertaken. However, as the circumstances continue to evolve, there may be disruptions to the future work timelines if employees, consultants or their respective families are personally impacted by COVID-19 or if travel and other operational restrictions are not lifted.

Having assessed the potential uncertainties relating to the Consolidated Entity's ability to effectively fund exploration activities and operating expenditures, the Directors believe that the Consolidated Entity will continue to operate as a going concern for the foreseeable future. Therefore, the Directors consider it is appropriate to prepare the financial statements on a going concern basis.

Rounding of amounts

3D Oil Limited is a type of Company that is referred to in ASIC Corporations (Rounding in Financial/Directors' Reports) Instrument 2016/191 and therefore the amounts contained in this report and in the financial report have been rounded to the nearest dollar.

Basis of preparation

These general purpose financial statements have been prepared in accordance with Australian Accounting Standards and Interpretations issued by the Australian Accounting Standards Board ('AASB') and the Corporations Act 2001, as appropriate for for-profit oriented entities. These financial statements also comply with International Financial Reporting Standards as issued by the International Accounting Standards Board ('IASB').

Historical cost convention

The financial statements have been prepared under the historical cost

convention, except for, where applicable, the revaluation of financial assets and liabilities at fair value through profit or loss, financial assets at fair value through other comprehensive income, investment properties, certain classes of property, plant and equipment and derivative financial instruments.

Critical accounting estimates

The preparation of the financial statements requires the use of certain critical accounting estimates. It also requires management to exercise its judgement in the process of applying the Consolidated Entity's accounting policies. The areas involving a higher degree of judgement or complexity, or areas where assumptions and estimates are significant to the financial statements, are disclosed in note 3.

Parent entity information

In accordance with the Corporations Act 2001, these financial statements present the results of the Consolidated Entity only. Supplementary information about the parent entity is disclosed in note 27.

Principles of consolidation

The consolidated financial statements incorporate the assets and liabilities of all subsidiaries of 3D Oil Limited ('Company' or 'parent entity') as at 30 June 2020 and the results of all subsidiaries for the year then ended. 3D Oil Limited and its subsidiaries together are referred to in these financial statements as the 'Consolidated Entity'.

Subsidiaries are all those entities over which the Consolidated Entity has control. The Consolidated Entity controls an entity when the Consolidated Entity is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power to direct the activities of the entity. Subsidiaries are fully consolidated from the date on which control is transferred to the Consolidated Entity. They are de-consolidated from the date that control ceases.

Intercompany transactions, balances and unrealised gains on transactions between entities in the Consolidated Entity are eliminated. Unrealised losses are also eliminated unless the transaction provides evidence of the impairment of the asset transferred. Accounting policies of subsidiaries have been changed where necessary to ensure consistency with the policies adopted by the Consolidated Entity.

The acquisition of subsidiaries is accounted for using the acquisition method of accounting. A change in ownership interest,

without the loss of control, is accounted for as an equity transaction, where the difference between the consideration transferred and the book value of the share of the non-controlling interest acquired is recognised directly in equity attributable to the parent.

Where the Consolidated Entity loses control over a subsidiary, it derecognises the assets including goodwill, liabilities and non-controlling interest in the subsidiary together with any cumulative translation differences recognised in equity. The Consolidated Entity recognises the fair value of the consideration received and the fair value of any investment retained together with any gain or loss in profit or loss.

Interest income

Interest revenue is recognised as interest accrues using the effective interest method. This is a method of calculating the amortised cost of a financial asset and allocating the interest income over the relevant period using the effective interest rate, which is the rate that exactly discounts estimated future cash receipts through the expected life of the financial asset to the net carrying amount of the financial asset.

Other revenue

Other revenue is recognised when it is received or when the right to receive payment is established.

Income tax

The income tax expense or benefit for the period is the tax payable on that period's taxable income based on the applicable income tax rate for each jurisdiction, adjusted by the changes in deferred

tax assets and liabilities attributable to temporary differences, unused tax losses and the adjustment recognised for prior periods, where applicable.

Deferred tax assets and liabilities are recognised for temporary differences at the tax rates expected to be applied when the assets are recovered or liabilities are settled, based on those tax rates that are enacted or substantively enacted, except for:

--When the deferred income tax asset or liability arises from the initial recognition of goodwill or an asset or liability in

a transaction that is not a business combination and that, at the time of the transaction, affects neither the accounting nor taxable profits; or

--When the taxable temporary difference is associated with interests in subsidiaries, associates or joint ventures, and the timing of the reversal can be controlled and it is probable that the temporary difference will not reverse in the foreseeable future.

Deferred tax assets are recognised for deductible temporary differences and unused tax losses only if it is probable that future taxable amounts will be available to utilise those temporary differences and losses.

The carrying amount of recognised and unrecognised deferred tax assets are reviewed at each reporting date. Deferred tax assets recognised are reduced to the extent that it is no longer probable that future taxable profits will be available for the carrying amount to be recovered. Previously unrecognised deferred tax assets are recognised to the extent that it is probable that there are future taxable profits available to recover the asset.

Deferred tax assets and liabilities are offset only where there is a legally enforceable right to offset current tax assets against current tax liabilities and deferred tax assets against deferred tax liabilities; and they relate to the same taxable authority on either the same taxable entity or different taxable entities which intend to settle simultaneously.

3D Oil Limited (the 'head entity') and its wholly-owned Australian subsidiaries have formed an income tax consolidated group under the tax consolidation regime. The head entity and each subsidiary in the tax consolidated group continue to account for their own current and deferred tax amounts. The tax consolidated group has applied the 'separate taxpayer within group' approach in determining the appropriate amount of taxes to allocate to members of the tax consolidated group.

Current and non- current classification

Assets and liabilities are presented in the statement of financial position based on current and non-current classification.

An asset is classified as current when: it is either expected to be realised or intended to be sold or consumed in the Consolidated Entity's normal operating cycle; it is held primarily for the purpose of trading; it is expected to be realised within 12 months after the reporting period; or the asset is cash or cash equivalent unless restricted from being exchanged or used to settle

a liability for at least 12 months after the reporting period. All other assets are classified as non-current.

A liability is classified as current when: it is either expected to be settled in the Consolidated Entity's normal operating cycle; it is held primarily for the purpose of trading; it is due to be settled within

12 months after the reporting period; or there is no unconditional right to defer the settlement of the liability for at least

12 months after the reporting period. All other liabilities are classified as non-current.

Deferred tax assets and liabilities are always classified as non-current.

Joint operations

A joint operation is a joint arrangement whereby the parties that have joint control of the arrangement have rights to the assets, and obligations for the liabilities, relating to the arrangement. The Consolidated Entity has recognised its share of jointly held assets, liabilities, revenues and expenses of joint operations. These have been incorporated in the financial statements under the appropriate classifications.

Exploration

Expenditure

Exploration expenditure incurred is accumulated in respect of each identifiable area of interest. These costs are only carried forward in relation to each area of interest to the extent the following conditions are satisfied:

1. the rights to tenure of the area of interest are current; and
2. at least one of the following conditions is also met:
3. 1. the exploration and evaluation expenditures are expected to be recouped through successful development and exploitation of the area of interest, or alternatively, by its sale; and
   2. exploration and evaluation activities in the area of interest have not at the reporting date reached a stage which permits a reasonable assessment of the existence or otherwise
      of economically recoverable reserves, and active and significant operations in, or in relation to, the area of interest are continuing.

Accumulated costs in relation to an abandoned area are written off in full against profit in the year in which the decision to abandon the area is made.

When production commences, the accumulated costs for the relevant area of interest are amortised over the life of the area according to the rate

of depletion of the economically recoverable reserves.

A regular review is undertaken of each area of interest to determine the appropriateness of continuing to carry forward cost in relation to that area of interest.

Costs of site restoration are provided over the life of the facility from when exploration commences and are included in the cost of that stage. Site restoration costs include the dismantling and removal of mining plant, equipment and building structures, waste removal, and rehabilitation of the site in accordance with clauses of the mining permits. Such costs have been determined using estimates of future costs, current legal requirements and technology on an undiscounted basis.

Any changes in the estimates for the costs are accounted on a prospective basis. In determining the costs of site restoration, there is uncertainty regarding the nature and extent of the restoration due to community expectations and future legislation. Accordingly the costs have been determined on the basis that the restoration will be completed within one year of abandoning the site.

Impairment of non-financial assets

Non-financial assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recognised for the amount by which the asset's carrying amount exceeds its recoverable amount.

Recoverable amount is the higher of an asset's fair value less costs of disposal and value-in-use. The value-in-use is the present value of the estimated future cash flows relating to the asset using a pre-tax discount rate specific to the asset or cash-generating unit to which the

asset belongs. Assets that do not have independent cash flows are grouped together to form a cash-generating unit.

Leases

At inception of a contract, the Consolidated Entity assesses whether a contract is, or contains, a lease. A contract is, or contains, a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. To assess whether a contract conveys the right to control the use of an identified asset, the Consolidated Entity assesses whether:

--The contract involves the use of an identified asset - this may be specified explicitly or implicitly and should

be physically distinct or represent substantially all of the capacity of a physically distinct asset. If the supplier has a substantive substitution right, then the asset is not identified;

--The Consolidated Entity has the right to obtain substantially all of the economic benefits from use of the asset throughout the period of use; and

--The Consolidated Entity has the right to direct the use of the asset. The Consolidated Entity has this right when it has the decision-making rights that are most relevant to changing how and for what purpose the asset is used. In rare cases where the decision about how and for what purpose the asset is used is predetermined, the Consolidated Entity has the right to direct the use of the asset if either:

--The Consolidated Entity has the right to operate the asset; or

--The Consolidated Entity designed the asset in a way that predetermine how and for what purpose it will be used.

This policy is applied to contracts entered into, or changed, on or after 1 July 2019.

At inception or on reassessment of a contract that contains a lease component, the Consolidated Entity allocates the consideration in the contract to each lease component on the basis of their relative stand-alone prices. However, for the leases of land and buildings in which it is a lessee, the Consolidated Entity has elected not to separate non-lease components and account for the lease and non-lease components as a single lease component.

As a lessee

The Consolidated Entity recognises a right- of-use asset and a lease liability at the lease commencement date. The right-of-use asset is initially measured at cost, which comprises the initial amount of the lease liability adjusted for any lease payments made at or before the commencement date, plus any initial direct costs incurred and an estimate of costs to dismantle and remove the underlying asset or to restore the underlying asset or the site on which it is located, less any lease incentives received.

The right-of-use asset is subsequently depreciated using the straight-line method from the commencement date to the earlier of the end of the useful life of

the right-of-use asset or the end of the lease term. The estimated useful lives of right-of-use assets are determined on the same basis as those of property and equipment. In addition, the right-of-use asset is periodically reduced by impairment losses, if any, and adjusted for certain remeasurements of the lease liability.

The lease liability is initially measured at the present value of the lease payments that are not paid at the commencement date, discounted using the interest rate implicit in the lease or, if that rate cannot be readily determined, the Consolidated Entity's incremental borrowing rate. Generally, the Consolidated Entity uses its incremental borrowing rate as the discount rate.

Lease payments included in the measurement of the lease liability comprise the following:

--Fixed payments, including in-substance fixed payments;

--Variable lease payments that depend on an index or a rate, initially measured using the index or rate as at the commencement date;

--Amounts expected to be payable under a residual value guarantee; and

--The exercise price under a purchase option that the Consolidated Entity is reasonably certain to exercise, lease payments in an optional renewal period if the Consolidated Entity is reasonably certain to exercise an extension option, and penalties for early termination of a lease unless the Consolidated Entity is reasonably certain not to terminate early.

The lease liability is measured at amortised cost using the effective interest method, It is remeasured when there is a change in future lease payments arising from

a change in an index or rate, if there is a change in the Consolidated Entity's estimate of the amount expected to be payable under a residual value guarantee, or if the Consolidated Entity changes its assessment of whether it will exercise a purchase, extension or termination option.

When the lease liability is remeasured in this way, a corresponding adjustment is made to the carrying amount of the right- of-use assets, or is recorded in profit or loss if the carrying amount of the right-of-use asset has been reduced to zero.

Short-term leases and leases of low-value assets

The Consolidated Entity has elected not to recognise right-of-use assets and lease liabilities for short-term leases that have a lease term of 12 months or less and leases of low-value assets, including IT equipment. The Consolidated Entity recognises the lease payments associated with these leases as an expense on a straight-line basis over the lease term.

Goods and Services Tax ('GST') and other similar taxes

Revenues, expenses and assets are recognised net of the amount of associated GST, unless the GST incurred is not recoverable from the tax authority. In this case it is recognised as part of the cost of the acquisition of the asset or as part of the expense.

Receivables and payables are stated inclusive of the amount of GST receivable or payable. The net amount of GST recoverable from, or payable to, the tax authority is included in other receivables or other payables in the statement of financial position.

Cash flows are presented on a gross basis. The GST components of cash flows arising from investing or financing activities which are recoverable from, or payable to the tax authority, are presented as operating cash flows.

Commitments and contingencies are disclosed net of the amount of GST recoverable from, or payable to, the tax authority.

Fair value measurement

When an asset or liability, financial or non-financial, is measured at fair value for recognition or disclosure purposes, the fair value is based on the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date; and assumes that the transaction will take place either: in the principal market; or in the absence of a principal market, in the most advantageous market.

Fair value is measured using the assumptions that market participants would use when pricing the asset or liability, assuming they act in their economic best interests. For non-financial assets, the fair value measurement is based on its highest and best use. Valuation techniques that are appropriate in the circumstances and for which sufficient data are available to measure fair value, are used, maximising the use of relevant observable inputs and minimising the use of unobservable inputs.

New Accounting Standards and Interpretations not yet mandatory or early adopted

Australian Accounting Standards and Interpretations that have recently been issued or amended but are not yet mandatory, have not been early adopted by the Consolidated Entity for the annual reporting period ended 30 June 2020. The Consolidated Entity has not yet assessed the impact of these new or amended Accounting Standards and Interpretations.

Note 3. Critical accounting judgements, estimates and assumptions

The preparation of the financial statements requires management to make judgements, estimates and assumptions that affect the reported amounts in the financial statements. Management continually evaluates its judgements and estimates in relation to assets, liabilities, contingent liabilities, revenue and expenses. Management bases its judgements, estimates and assumptions on historical experience and on other various factors, including expectations of future events, management believes to

be reasonable under the circumstances. The resulting accounting judgements and estimates will seldom equal the related actual results. The judgements, estimates and assumptions that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities (refer to the respective notes) within the next financial year are discussed below.

Coronavirus (COVID-19) pandemic

Judgement has been exercised in considering the impacts that the Coronavirus (COVID-19) pandemic has had, or may have, on the Consolidated Entity based on known information. This consideration extends to the nature of the products and services offered, customers, supply chain, staffing and geographic regions in which the Consolidated Entity operates. Other than as addressed in specific notes, there does not currently appear to be either any significant impact upon the financial statements or any significant uncertainties with respect to events or conditions which may impact the Consolidated Entity unfavourably as at the reporting date or subsequently as a result of the Coronavirus (COVID-19) pandemic.

Estimation of useful lives of assets

The Consolidated Entity determines the estimated useful lives and related depreciation and amortisation charges for its property, plant and equipment and finite life intangible assets. The useful lives could change significantly as a result of technical innovations or some other event. The depreciation and amortisation charge will increase where the useful lives are less than previously estimated lives, or technically obsolete or non-strategic assets that have been abandoned or sold will be written off or written down.

Income tax

The Consolidated Entity is subject to income taxes in the jurisdictions in which it operates. Significant judgement is required in determining the provision for income tax. There are many transactions and calculations undertaken during the ordinary course of business for which the ultimate tax determination is uncertain. The Consolidated Entity recognises liabilities for anticipated tax audit issues based on the Consolidated Entity's current understanding of the tax law. Where the final tax outcome of these matters is different from the carrying amounts, such differences will impact the current and deferred tax provisions in the period in which such determination is made.

Recovery of deferred tax assets

Deferred tax assets are recognised for deductible temporary differences only if the Consolidated Entity considers it is probable that future taxable amounts will be available to utilise those temporary differences and losses.

Lease term

The lease term is a significant component in the measurement of both the right-of- use asset and lease liability. Judgement is exercised in determining whether there is reasonable certainty that an option to extend the lease or purchase the underlying asset will be exercised, or an option to terminate the lease will not be exercised, when ascertaining the periods to be included in the lease term. In determining the lease term, all facts and circumstances that create an economical incentive to exercise an extension option, or not to exercise a termination option, are considered at the lease commencement date. Factors considered may include the importance of the asset to the Consolidated Entity's operations; comparison of terms and conditions to prevailing market rates; incurrence of significant penalties; existence of significant leasehold improvements; and the costs and disruption to replace the asset. The Consolidated Entity reassesses whether it is reasonably certain to exercise an extension option, or not exercise a termination option, if there is a significant event or significant change in circumstances.

Incremental borrowing rate

Where the interest rate implicit in a lease cannot be readily determined, an incremental borrowing rate is estimated to discount future lease payments to measure the present value of the lease liability at the lease commencement date. Such a rate is based on what the Consolidated Entity estimates it would have to pay a third party to borrow the funds necessary to obtain an asset of a similar value to

the right-of-use asset, with similar terms, security and economic environment.

Employee benefits provision

As discussed in note 2, the liability for employee benefits expected to be settled more than 12 months from the reporting date are recognised and measured

at the present value of the estimated future cash flows to be made in respect of all employees at the reporting date. In determining the present value of the liability, estimates of attrition rates and pay increases through promotion and inflation have been taken into account.

Exploration and evaluation costs

Exploration and evaluation costs have been capitalised on the basis that the Consolidated Entity will commence commercial production in the future, from which time the costs will be amortised in proportion to the depletion of the mineral resources. Key judgements are applied in considering costs to be capitalised which includes determining expenditures directly related to these activities and allocating overheads between those that are expensed and capitalised. In addition, costs are only capitalised that are expected to be recovered either through successful development

or sale of the relevant mining interest. The expectation of recovery of the costs capitalised is based on the assumption that the Group will be able to obtain adequate financing to allow the continued exploration and subsequent development of areas of interest by either successfully farming out a proportion of existing permits or raising adequate capital in its own right. To the extent that capitalised costs are determined not to be recoverable in the future, they will be written off in the period in which this determination is made.

Note 4. Operating segments

AASB 8 requires operating segments to be identified on the basis of internal reports about the components of the Consolidated Entity that are regularly reviewed by the chief decision maker in order to allocate resources to the segment and to assess its performance. 3D Oil Limited operates in the development of oil and gas within Australia. The Consolidated Entity's activities are therefore classified as one operating segment.

The chief decision makers, being the Board of Directors, assess the performance of the Consolidated Entity as a whole and as such through one segment.

Accounting policy for operating segments

Operating segments are presented using the 'management approach', where the information presented in this financial

statements is on the same basis as the internal reports provided to the Chief Operating Decision Makers ('CODM'). The CODM is responsible for the allocation of resources to operating segments and assessing their performance.

COVID-19 incentives represent the job keeper and cash flow boost payments received from Federal Government in response to ongoing novel coronavirus (COVID-19) pandemic. Government grants are recognised in the financial statements at expected values or actual cash received when there is a reasonable assurance that

the Consolidated Entity will comply with the requirements and that the grant will be received. The Consolidated Entity has recognised its share of revenues, expenses and expenses reimbursements of joint operations, which give rise to job keeper payments, within exploration assets in the financial statements.

Petroleum Resource Rent Tax

Petroleum Resource Rent Tax (PRRT) applies to petroleum projects in Australian onshore and offshore areas under the Petroleum Resource Rent Tax Assessment Act 1987. PRRT is assessed on a project basis or production licence area and

is levied on the taxable profits of a petroleum project at a rate of 40%. Eligible expenditure incurred in relation to permits VIC/P57, VIC/P74, T/49P and WA-527-P, attach to the permit and can be carried forward. Certain specified undeducted expenditure is eligible for annual

compounding at set rates. The compound amount can be deducted against assessable receipts in future years.

The Company has not recognised a deferred tax asset with respect to the carried forward undeducted expenditure.

The above potential tax benefit, which excludes tax losses, for deductible temporary differences has not been recognised in the statement of financial position as the recovery of this benefit is uncertain.

The taxation benefits of tax losses and temporary difference not brought to account will only be obtained if:

1. the Consolidated Entity derives future assessable income of a nature and of an amount sufficient to enable the benefit from the deductions for the losses to be realised;

1. the Consolidated Entity continues to comply with the conditions for deductibility imposed by law; and
2. no change in tax legislation adversely affects the Company in realising the benefits from deducting the losses.

Accounting policy for cash and cash equivalents

Cash and cash equivalents includes cash on hand, deposits held at call with financial institutions, other short-term, highly

liquid investments with original maturities of three months or less that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value.

Trade receivables represent reimbursement of labour costs and third party invoices by JV partners.

The average credit period on trade and other receivables is 30 days. No interest is charged on the receivables. The Consolidated Entity has financial risk management policies in place to ensure that all receivables are received within the credit timeframe. Due to the short-term nature of these receivables, their carrying value is assumed to be approximate to their fair value.

Accounting policy for trade and other receivables

Trade receivables are initially recognised at fair value and subsequently measured at amortised cost using the effective interest method, less any allowance for expected credit losses. Trade receivables are generally due for settlement within 30 days.

Other receivables are recognised at amortised cost, less any allowance for expected credit losses.

Accounting policy for furniture and computer equipment

Furniture and computer equipment are stated at historical cost less accumulated depreciation and impairment. Historical cost includes expenditure that is directly attributable to the acquisition of the items.

Depreciation is calculated on a straight- line basis to write off the net cost of each item of property, plant and equipment (excluding land) over their expected useful lives as follows:

The residual values, useful lives and depreciation methods are reviewed, and adjusted if appropriate, at each reporting date.

Note 12. Non- current assets

• Right-of-useassets

The Consolidated Entity has lease arrangements for office space. Rental contracts are typically made for fixed periods of 12 to 36 months but may have an extension option. This note provides information for leases where the Consolidated Entity is a lessee.

Lease terms are negotiated on an individual basis and may contain a wide range of different terms and conditions. The lease agreements do not impose any covenants other than th e security interests in the leased assets that are held by the lessor. Leased assets may not be used as security for borrowing purposes.

Right-of-use assets and lease liabilities

The Consolidated Entity has adopted AASB 16 Leases (AASB 16) on 1 July 2019 but has not restated comparatives for the 2019 reporting period, as permitted under the specific transition provisions in the standard. The reclassifications and the adjustments arising from the new leasing rules are therefore recognised in the opening balance sheet on 1 July 2019.

On adoption of AASB 16, the Consolidated Entity recognised lease assets (known as 'right-of-use') and liabilities in relation to leases which had previously been classified as 'operating leases' under the principles of AASB 117 Leases. These assets and liabilities were measured at the present value of the remaining lease payments, discounted using the lessee's incremental borrowing rate as of 1 July 2019. In applying AASB 16

for the first time, the Consolidated Entity has used the following practical expedients permitted by the standard:

--applying a single discount rate to a portfolio of leases with reasonably similar characteristics

--relying on previous assessments on whether leases are onerous as an alternative to performing an impairment review - there were no onerous contracts as at 1 July 2019

--accounting for operating leases with a remaining lease term of less than 12 months as at 1 July 2019 as short-term leases

--excluding initial direct costs for the measurement of the right-of-use asset at the date of initial application, and

--using hindsight in determining the lease term where the contract contains options to extend or terminate the lease.

The Consolidated Entity has also elected not to reassess whether a contract is, or contains a lease at the date of initial application. Instead, for contracts entered into before the transition date the group relied on its assessment made applying AASB 117 and Interpretation 4 Determining whether an Arrangement contains a Lease.

The statement of financial position shows the following amounts relating to right of use assets:

Refer note 16 and 18 to these financial statements for the current and non-current lease liabilities. Depreciation expenses of right of use assets and finance charges on lease liabilities are presented in note 6 to the financial statements.

The Consolidated Entity had no short-term lease arrangements during the year ended 30 June 2020.

On adoption of AASB 16, the Consolidated Entity recognised lease liabilities in relation to leases which had previously been classified as 'operating leases' under the principles of AASB 117 Leases. These liabilities were measured at the present value of the remaining lease payments, discounted using the lessee's incremental borrowing rate as of 1 July 2019.

The weighted average lessee's incremental borrowing rate applied to the lease liabilities on 1 July 2019 was 7.5%.

Accounting policy for right-of-use assets

A right-of-use asset is recognised at the commencement date of a lease. The right-of-use asset is measured at cost, which comprises the initial amount of the lease liability, adjusted for, as applicable, any lease payments made at or before the commencement date net of any lease incentives received, any initial direct costs incurred, and, except where included in the

cost of inventories, an estimate of costs expected to be incurred for dismantling and removing the underlying asset, and restoring the site or asset.

Right-of-use assets are depreciated on a straight-line basis over the unexpired period of the lease or the estimated useful life of the asset, whichever is the shorter. Where the Consolidated Entity expects to obtain ownership of the leased asset at the end of the lease term, the depreciation is over its

estimated useful life. Right-of use assets are subject to impairment or adjusted for any remeasurement of lease liabilities.

The Consolidated Entity has elected not to recognise a right-of-use asset and corresponding lease liability for short-term leases with terms of 12 months or less and leases of low-value assets. Lease payments on these assets are expensed to profit or loss as incurred.

Accounting policy for intangible assets

Intangible assets acquired as part of a business combination, other than goodwill, are initially measured at their fair value at the date of the acquisition. Intangible assets acquired separately are initially recognised at cost. Indefinite life intangible assets are not amortised and are subsequently measured at cost less any impairment. Finite life intangible assets are subsequently measured at cost

less amortisation and any impairment. The gains or losses recognised in profit or loss arising from the derecognition of intangible assets are measured as the difference between net disposal proceeds and the carrying amount of the intangible asset. The method and useful lives of finite life intangible assets are reviewed annually. Changes in the expected pattern of consumption or useful life are accounted for prospectively by changing the amortisation method or period.

Software

Significant costs associated with software are deferred and amortised on a straight- line basis over the period of their expected benefit, being their finite life of 5 years.

The exploration and evaluation assets relate to VIC/P57 and VIC/P74 offshore Gippsland Basin in Victoria, T/49P offshore Otway Basin in Tasmania and WA-527-P in Western Australia. The recoverability of the carrying amounts of the exploration and evaluation expenditure is dependent on the successful development and commercial exploitation, or alternatively the sale, of the respective areas of interest.

The Company carried out an impairment review of the carrying amount of its exploration expenditure in VIC/P57, VIC/P74, T/49P and WA-527-P as at

30 June 2020. Following a review by the Directors and management, the book value of VIC/P57 was written down to Nil as at 30 June 2020, reflecting the estimated future economic benefits expected to be derived from this area of interest.

On 18 December 2019, 3D Oil T49P Pty Ltd, a wholly owned subsidiary of the Company, entered a Farmout Agreement ('FOA') in relation to the offshore Tasmanian Permit T/49P with ConocoPhillips Australia SH1 Pty Ltd. During the year, the Company announced that it had received required regulatory approvals and executed a Joint Operating Agreement ('JOA'). Under the JOA, the Company transferred 80% interest in the permit to ConocoPhillips Australia SH1 Pty Ltd. In accordance with the FOA and JOA, ConocoPhillips Australia SH1 Pty Ltd has paid $5,000,000 to the Company in recognition of previous permit expenditure. Cash consideration received directly from the farminee is credited against costs previously capitalised in relation to the whole interest.

Farm-out in the exploration and evaluation phase

The Consolidated Entity does not record any expenditure made by the farminee on its account. It also does not recognise any gain or loss on its exploration and evaluation farm-out arrangements

but redesignates any costs previously capitalised in relation to the whole interest as relating to the partial interest retained. Any cash consideration received directly from the farminee is credited against costs previously capitalised in relation to the whole interest with any excess accounted for by the farmor as a gain on disposal.

Accounting policy for exploration and evaluation assets

Exploration and evaluation expenditure in relation to separate areas of interest for which rights of tenure are current is carried forward as an asset in the statement of financial position where it is expected that the expenditure will be recovered through the successful development and exploitation of an area of interest, or by its sale; or exploration activities are continuing in an area and activities have not reached a stage which permits a reasonable estimate of the existence or otherwise of economically recoverable reserves. Where a project or an area of interest has been abandoned, the expenditure incurred thereon is written off in the year in which the decision is made.

Refer to note 22 for further information on financial instruments.

Accounting policy for trade and other payables

These amounts represent liabilities for goods and services provided to the

Consolidated Entity prior to the end of the financial year and which are unpaid. Due to their short-term nature they are measured at amortised cost and are not discounted.

The amounts are unsecured and are usually paid within 30 days of recognition.

Refer to note 22 for further information on financial instruments.

The changes in the Consolidated Entity's total lease liabilities (current and non- current) arising from financing activities can be classified as follows:

The Consolidated Entity received a 30% reduction in rent payments for two months from the landlord, in response to ongoing COVID-19 pandemic. There are no other

changes to the lease. The forgiveness of rent is unconditional and qualifies to be accounted using the practical expedient of AASB 16 Leases. Applying the practical

expedient, the Consolidated Entity recognised this forgiveness of rent as a negative variable lease payment in the profit or loss.

Refer to note 22 for further information on financial instruments.

Accounting policy for lease liabilities

A lease liability is recognised at the commencement date of a lease. The lease liability is initially recognised at the present value of the lease payments to be made over the term of the lease, discounted using the interest rate implicit in the lease or, if that rate cannot be readily determined, the Consolidated Entity's incremental

borrowing rate. Lease payments comprise of fixed payments less any lease incentives receivable, variable lease payments that depend on an index or a rate, amounts expected to be paid under residual value guarantees, exercise price of a purchase option when the exercise of the option

is reasonably certain to occur, and any anticipated termination penalties. The variable lease payments that do not depend on an index or a rate are expensed in the period in which they are incurred.

Lease liabilities are measured at amortised cost using the effective interest method. The carrying amounts are remeasured if there is a change in the following: future lease payments arising from a change in an index or a rate used; residual guarantee; lease term; certainty of a purchase option and termination penalties. When a lease liability is remeasured, an adjustment is made to the corresponding right-of use asset, or to profit or loss if the carrying amount of the right-of-use asset is fully written down.

Accounting policy for long- term employee benefits

The liability for long service leave not expected to be settled within 12 months of the reporting date are measured as the present value of expected future payments

to be made in respect of services provided by employees up to the reporting date using the projected unit credit method. Consideration is given to expected future wage and salary levels, experience of employee departures and periods of

service. Expected future payments are discounted using market yields at the reporting date on high quality corporate bond rates with terms to maturity and currency that match, as closely as possible, the estimated future cash outflows.

Ordinary shares

Ordinary shares entitle the holder to participate in dividends and the proceeds on the winding up of the Company in proportion to the number of and amounts paid on the shares held. The fully paid ordinary shares have no par value and the Company does not have a limited amount of authorised capital.

On a show of hands every member present at a meeting in person or by proxy shall have one vote and upon a poll each share shall have one vote.

Capital risk management

The company's objectives when managing capital are to safeguard its ability to continue as a going concern, so that it can provide returns for shareholders and benefits for other stakeholders and to maintain an optimum capital structure to reduce the cost of capital.

Capital is regarded as total equity, as recognised in the statement of financial position, plus net debt. Net debt is calculated as total borrowings less cash and cash equivalents.

In order to maintain or adjust the capital structure, the Company may adjust the amount of dividends paid to shareholders, return capital to shareholders, issue new shares or sell assets to reduce debt.

The Consolidated Entity would look to raise capital when an opportunity to invest in a business or Company was seen as value adding relative to the current parent entity's share price at the time of the investment. The Company is not actively pursuing additional investments in the short term as it continues to integrate and grow its existing businesses in order to maximise synergies.

The capital risk management policy remains unchanged from the 30 June 2019 Annual Report.

Accounting policy for issued capital

Ordinary shares are classified as equity.

Incremental costs directly attributable to the issue of new shares or options are shown in equity as a deduction, net of tax, from the proceeds.

Note 21. Equity - Dividends

There were no dividends paid or declared during the current or previous financial year.

The Consolidated Entity does not have franking credits available for subsequent financial years.

Accounting policy for dividends

Dividends are recognised when declared during the financial year and no longer at the discretion of the Company.

Financial risk management objectives

The Consolidated Entity's activities expose it to a variety of financial risks: market risk (including foreign currency risk, price risk and interest rate risk), credit risk and liquidity risk. The Consolidated Entity's overall risk management program focuses on the unpredictability of financial markets and seeks to minimise potential adverse effects on the financial performance of the Consolidated Entity. The Consolidated Entity uses different methods to measure different types of risk to which it is exposed. These methods include sensitivity analysis in the case of interest rate, foreign exchange and other price risks, ageing analysis for credit risk and beta analysis

in respect of investment portfolios to determine market risk.

Risk management is carried out by senior finance executives ('Finance') under policies approved by the Board of Directors ('the Board'). These policies include identification and analysis of the risk exposure of the Consolidated Entity and appropriate procedures, controls and risk limits. Finance identifies, evaluates and hedges financial risks within the Consolidated Entity's operating units. Finance reports to the Board on a monthly basis.

Market risk

Foreign currency risk

The Consolidated Entity undertakes certain transactions denominated in foreign currency and is exposed to foreign currency risk through foreign exchange rate fluctuations. The Consolidated Entity operates a US dollar bank account for the purpose of transacting in US dollars.

Foreign exchange risk arises from future commercial transactions and recognised financial assets and financial liabilities denominated in a currency that is not the entity's functional currency. The risk is measured using sensitivity analysis and cash flow forecasting.

The carrying amount of the Consolidated Entity's foreign currency denominated financial assets and financial liabilities at the reporting date were as follows:

The Consolidated Entity operated a US dollar bank account. There were no other assets or liabilities denominated in foreign currencies at the year end. The US balance on the account was US$23 and the exchange rate used to translate the balance at 30 June 2020 was $0.6878 (30 June 2019: $0.69768).

Price risk

The Consolidated Entity is not exposed to any significant price risk.

Interest rate risk

The Consolidated Entity's only exposure to interest rate risk is in relation to deposits held. Deposits are held with reputable banking financial institutions.

The tables below illustrate the impact on profit before tax based upon expected volatility of interest rates using market data and analysis forecasts.

Credit risk

Credit risk refers to the risk that a counterparty will default on its contractual obligations resulting in financial

loss to the Consolidated Entity. The Consolidated Entity has a strict code of credit, including obtaining agency credit information, confirming references and setting appropriate credit limits. The Consolidated Entity obtains guarantees where appropriate to mitigate credit risk. The maximum exposure to credit risk at the reporting date to recognised financial assets is the carrying amount, net of any provisions for impairment of those assets, as disclosed in the statement of financial position and notes to the financial statements. The Consolidated Entity does not hold any collateral.

The Consolidated Entity has adopted a lifetime expected loss allowance in estimating expected credit losses to trade receivables through the use of a

provisions matrix using fixed rates of credit loss provisioning. These provisions are considered representative across all customers of the Consolidated Entity based on recent sales experience, historical collection rates and forward-looking information that is available.

Generally, trade receivables are written off when there is no reasonable expectation of recovery. Indicators of this include the failure of a debtor to engage in a repayment plan, no active enforcement activity and a failure to make contractual payments for a period greater than 1 year.

Liquidity risk

Vigilant liquidity risk management requires the Consolidated Entity to maintain sufficient liquid assets (mainly cash and cash equivalents) and available borrowing facilities to be able to pay debts as and when they become due and payable.

The Consolidated Entity manages liquidity risk by maintaining adequate cash reserves and available borrowing facilities by continuously monitoring actual and forecast cash flows and matching the maturity profiles of financial assets and liabilities.

Remaining contractual maturities

The following tables detail the Consolidated Entity's remaining contractual maturity for its financial instrument liabilities. The tables have been drawn up based on

the undiscounted cash flows of financial liabilities based on the earliest date on which the financial liabilities are required to be paid. The tables include both interest and principal cash flows disclosed as remaining contractual maturities and therefore these totals may differ from their carrying amount in the statement of financial position.

The cash flows in the maturity analysis above are not expected to occur significantly earlier than contractually disclosed above.

Fair value of financial instruments

Unless otherwise stated, the carrying amounts of financial instruments reflect their fair value. The carrying amounts of trade receivables and trade payables are assumed to approximate their fair values due to their short-term nature. Where appropriate, the fair value of financial liabilities is estimated by discounting the remaining contractual maturities at the current market interest rate that is available for similar financial instruments.

In order to maintain current rights of tenure to exploration tenements, the Consolidated Entity is required to outlay rentals and to meet the minimum work requirements and associated indicative expenditure of the National Offshore Petroleum Titles Administrator ('NOPTA'). Minimum commitments may be subject to renegotiation and with approval may otherwise be avoided by sale, farm out or relinquishment. These obligations are therefore not provided for in the financial statements as payable.

In relation to VIC/P57, the joint venture applied to NOPTA in September 2017 for a further 5 year tenure. The program includes minor but, high impact and carefully designed work commitments including state-of-the-art reprocessing of the 3D seismic data covering the permit. The Company announced on 7 March 2018 the renewal of the permit by NOPTA for a further five years.

In relation to VIC/P74, the Company has included its commitments for indicative expenditure in the above note relating to VIC/P74 up to the end of Year 3. Commitments from Year 4 onwards are confirmed on a year-by-year basis dependent on the Company agreeing to proceed. If the Company was to proceed beyond Year 3 in relation to VIC/P74, the current indicative expenditure commitment for Years 4-7 is currently gross $42.1 million and this would be occurring in 2022-2025 years.

In relation to WA-527-P, the Company has included its commitments for indicative expenditure in the above note relating to WA-527-P up to the end of Year 3. Commitments from Year 4 onwards

are confirmed on a year-by-year basis dependent on the Company agreeing to proceed. If the Company was to proceed beyond Year 3 in relation to WA-527-P, the current indicative expenditure commitment for Years 4-6 is currently gross $30.8 million and this would be occurring in 2021-2025 years.

The commitments above does not include commitments for indicative expenditure relating to Exploration Permit T/49P, as they are expected to be covered by the farm-in partner, ConocoPhillips Australia Pty Ltd, as per JOA. Under the terms of JOA TDO will contribute 10% of the joint operation expenses until ConocoPhillips Australia has completed an exploration well or spent at least US$30 million toward drilling of an exploration well.

Note 26. Related party transactions

Parent entity

3D Oil Limited is the parent entity.

Subsidiaries

Interests in subsidiaries are set out in note 28.

Joint operations

Interests in joint operations are set out in note 29.

Key management personnel

Disclosures relating to key management personnel are set out in note 23 and the remuneration report included in the Directors' report.

Transactions with related parties

There were no transactions with related parties during the current and previous financial year.

Receivable from and payable to related parties

There were no trade receivables from or trade payables to related parties at the current and previous reporting date.

Loans to/from related parties

There were no loans to or from related parties at the current and previous reporting date.

Guarantees entered into by the parent entity in relation to the debts of its subsidiaries

The parent entity had no guarantees in relation to the debts of its subsidiaries as at 30 June 2020 and 30 June 2019.

Contingent liabilities

The parent entity had no contingent liabilities as at 30 June 2020 and 30 June 2019.

Capital commitments - Property, plant and equipment

The parent entity had no capital commitments for property, plant and equipment as at 30 June 2020 and 30 June 2019.

Significant accounting policies

The accounting policies of the parent entity are consistent with those of the Consolidated Entity, as disclosed in note 2, except for the following:

--Investments in subsidiaries are accounted for at cost, less any impairment, in the parent entity.

--Investments in associates are accounted for at cost, less any impairment, in the parent entity.

--Dividends received from subsidiaries are recognised as other income by the parent entity and its receipt may be an indicator of an impairment of the investment.

--Significant estimates and judgement - recoverability of loan to subsidiary. No objective indicators of impairment as the current best estimates of potential resources indicate a quantity of oil/gas that would allow recovery of the amount due in full.

On 14 July 2020, the Company announced that it has been awarded the necessary environmental approvals from the Commonwealth Statuary National Agency, NOPSEMA, to acquire the Sauropod

3D Marine Seismic Survey (MSS) within 100% owned WA-527-P of the Offshore Roebuck Basin.

No other matter or circumstance has arisen since 30 June 2020 that has significantly affected, or may significantly affect

the Consolidated Entity's operations, the results of those operations, or the Consolidated Entity's state of affairs in future financial years.

Accounting policy for earnings per share

Basic earnings per share

Basic earnings per share is calculated by dividing the loss attributable to the owners of 3D Oil Limited, excluding any costs

of servicing equity other than ordinary shares, by the weighted average number of ordinary shares outstanding during the financial year, adjusted for bonus elements in ordinary shares issued during the financial year.

Diluted earnings per share

Diluted earnings per share adjusts the figures used in the determination of basic earnings per share to take into account the after income tax effect of interest and other financing costs associated with dilutive potential ordinary shares and the weighted average number of shares assumed to have been issued for no consideration in relation to dilutive potential ordinary shares.

As all of the tenements held by 3D Oil Limited are in the exploration stage, qualifying exploration expenditure is capitalised in accordance with Australian Accounting Standard AASB 6 Exploration for and Evaluation of Mineral Resources.

The company is required to assess at each reporting date if there are any triggers for impairment which may suggest the carrying value is in excess of the recoverable value. Any impairment losses are then measured in accordance with AASB 136 Impairment of Assets.

This area is a key audit matter as significant judgement is required in determining whether the facts and circumstances suggest that the carrying amount of an exploration and evaluation asset may exceed its recoverable amount, and then consequently in measuring any impairment loss.

Our procedures included, amongst others:

• Obtaining management's reconciliation of capitalised exploration and evaluation expenditure and agreeing to the general ledger;
• Selecting a sample of capitalised exploration and evaluation expenditure and obtaining documentation to support the amount capitalised in line with AASB 6;
• Reviewing management's treatment of the Joint Operating Agreement entered into during the period;
• Critically reviewing management's assessment of impairment indicators for the Group's capitalised exploration assets under AASB 6 by:

• assessing whether the period for the right to explore the areas of interest has not expired or will not expire in the near future without an expectation of renewal;
• making enquires of management regarding their intentions to carry out exploration and evaluation activity in the relevant exploration area, including review of managements' budgeted expenditure;

3D Oil is in the exploration and evaluation phase and therefore does not generate revenue from its operations and relies on funding from its shareholders or other sources to continue as a going concern.

These funds are used to meet expenditure requirements to maintain the good standing of the Group's tenements, progress project feasibility studies, and to cover corporate overheads.

Under AASB 101: Presentation of Financial Statements the directors of 3D Oil are required to assess the appropriateness of the preparation of the financial report on a going concern basis.

Our procedures included, amongst others:

• Assessing the going concern assumptions for reasonableness by discussing with management and reviewing board minutes;
• Obtaining and reviewing a copy of management's cash-flow forecast for mathematical accuracy and assessed whether it appears the current cash levels can sustain the operations of the Group for the 12 month period from date of signing of the financial statements;
• Reviewing the inputs and assumptions used by management in the cash flow forecasts for reasonableness and consistency and minimum exploration expenditure required under existing permits;
• Considering the impact of any subsequent events on the going concern assessment and