3D Oil Limited
Annual Report 2021

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E X P L O R A T I O N E X P L O R A T I O N E X P L O R A T I O N E X P L O R A T I O N E X P L O R A T I O N E X P L O R A I O N E X P L X P L X X X L L L L L R A R A R A R A A A N N N I I I I I I I I ANN UAL REP ORT 202 1 S AME R OCKS NEW IDEAS NEW IDEAS NEW O PP ORTUNIT Y 2 NEW OPP ORT UNIT Y ‘There are probably no other shareholders in a small oil and gas explorer in Australia exposed to so much upside.’ NOEL NEWEL L, EXECUTIVE CH AIR MAN Executive Chairman’s Letter to shareholders Review of Operations Directors' report Auditor's independence declaration Consolidated statement of profit or loss and other comprehensive income Consolidated statement of financial position Consolidated statement of changes in equity Consolidated statement of cash flows Notes to the consolidated financial statements Directors' declaration Independent auditor's report to the members of 3D Oil Limited Shareholder information Corporate directory 4 6 20 29 31 32 33 34 35 57 58 62 64 3 EXECUTIVE CHAIRMAN’S LETTER TO SHAR EHOLD ERS 4 In this world of emissions reduction, I would like to discuss my view on the relevance of the oil and gas industry going forward, but first up I must address some of the highlights for 3D Oil in the last year. 3D Oil is firmly on a course to become an east coast gas producer in a critical time of energy transition and constraint. As I write this the Geo Coral seismic vessel is currently in Bass Strait acquiring the Sequoia 3D Seismic Survey in T/49P for ConocoPhillips as operator. It is a very exciting time for both companies as we are about to reveal the gas potential of an area 3D Oil has championed for almost ten years. 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 significantly large gas reserves can potentially be uncovered. There is nowhere else. 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. The acquisition will almost certainly go significantly over budget largely due to weather, but 3D Oil has no exposure to cost over runs. And in the event COP decide to drill, 3D Oil shall be carried for the first US$30 mill of expenditure. There are probably no other shareholders in a small oil and gas explorer in Australia exposed to so much upside – and this is without considering our other exploration permits. Once again, I need to compliment my team for the acquisition of WA-527-P permit prior to the discovery of Dorado – it was a strategic master stroke, leveraging excellent technical insights and balancing risk versus reward in a highly underexplored area with exciting play concepts. It was not an accident or luck. We now see the development of the Dorado oil field moving forward, next door to our permit, with two exciting exploration wells to be drilled in the coming months – Pavo and Apus. 3D Oil are planning the acquisition of 3D seismic in WA-527-P early in 2022 – preferably and likely with a partner. The acquisition of the Gippsland Basin permit VIC/P74 with a near minimal bid continues to reveal leads and prospects which have not been previously recognized by the industry – in an area adjacent to the largest oil field discovered in Australia – Kingfish. We have been surprised by the unsolicited approaches we have received from potential farm-in partners to evaluate the permit – our team has spent much of this year engaged with these parties. Recently we released an ASX announcement that revealed further Prospective Resources in the permit. It must be remembered the commercial threshold within this area is relatively low due to its proximity to existing infrastructure. The recent report from the Inter-governmental Panel on Climate Change shows the world has no other option but to take practical steps to address the challenge. However, in the media the role of hydrocarbons moving forward is often portrayed as a binary debate – one of good vs evil – that we must immediately stop using any hydrocarbons. As our shareholders realise, the world of energy supply and the global economy are far more complicated and energy-dependent than that. Hydrocarbons, including gas, still supplied 83 per cent of all global energy in 2020. Even in the world of electric vehicles, oil and gas is integral to manufacturing of components. Thousands of products depend on oil and natural gas, from smart-phones and computers to sporting equipment and the clothes on your back. Petrochemicals are used in about half a million different products! A more rational debate would be about how technology can help us achieve net zero while maintaining affordable and reliable energy. APPEA recently estimated that our industry provides $66 billion of royalties, used to build hospitals, police stations, roads and schools. The industry has contributed $450 billion of investment into regional communities, and either directly or indirectly placed 80,000 people into jobs. The Australian government estimates gas exports have the potential to lower emissions in LNG-importing countries by about 170 million tonnes of CO2 equivalent per year by providing an alternative to higher emissions fuels. That equates to almost a third of Australia’s total annual emissions. Natural gas has only half the greenhouse gas emissions of coal when used to generate electricity and can currently achieve things that renewables simply cannot do, such as power manufacturing plants and provision of reliable energy base load. Of course, our industry can contribute significantly to de-carbonization – we can and are championing technologies such as Carbon Capture and Storage (CCS) and the production of blue hydrogen utilising natural gas feedstock. 3D Oil is now fully committed to becoming a significant east coast gas producer – a resource that remains an essential component to an energy mix with increasing reliance on renewables. In Victoria alone more than two million homes are connected to natural gas (83% of homes), 65,000 commercial gas customers and more than 600 large industrial users of natural gas. Victoria needs reliable and cheaper energy that comes from natural gas. According to Canstar, gas running costs are approximately 30 to 45 per cent lower than their electricity counterparts and that doesn’t consider the cost to convert your home from gas to electricity. Arguably, displacing gas energy sources with electricity in Victoria would result in uptake of proportionally higher dirtier fuel sources, as the state’s electricity production is heavily reliant on brown coal which makes up more than 70% of our energy mix. Renewable energy currently makes up the equivalent of just 4 per cent of Victoria’s energy consumption. As we have seen other parts of the world such as Britain, Europe, the US and elsewhere, natural gas plays a critical role in complementing intermittent renewable energy sources such as wind and solar. Gas has a critical role in any cleaner energy future. The role of natural gas as a lower emitting and cleaner burning fuel is driving much of the international demand for liquefied natural gas (LNG). Gas demand in Asia is booming largely driven by China with surging energy demand, gas replacing coal and low hydro output. As I write this, we are witnessing a global gas shortage. In many countries, including Britain and Spain, governments are rushing through emergency measures to protect consumers. Factories are being temporarily switched off, from aluminum smelters in Mexico to fertilizer plants in Britain. Markets are frantic. One trader says it is like the global financial crisis for commodities. While reasons behind this are incredibly complex, they can be reduced to a simple explanation – an energy market with only thin safety buffers, that has become acutely sensitive to disruptions with a back-drop of subdued investment in fossil fuels. Volatility in the global gas market is here to stay. It remains a challenging time in our industry with access to funds becoming increasingly hard and the volatility in global markets due to COVID. Despite these difficulties the company is in a unique position in our sector with the potential for massive uplifts in the very near future. I am aware we have many patient shareholders as we have slowly built our world class portfolio, all the while avoiding significant capital raisings over the life of the company. As a significant shareholder I believe we are close to reaping the rewards. 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 energy company. Noel Newell Executive Chairman 5 REVIEW OF OPER ATIONS 6 WA/527-P, BEDOUT SUB-BASIN, OFFSHORE NORTHWEST SHELF Exploration permit WA/527-P is a large permit that covers 6,500km2 of the eastern margin of the Bedout Sub-basin, a structural element of the Roebuck Basin on the prolific Northwest Shelf. The permit is situated approximately 80km northeast of the recent Dorado Field oil and gas condensate discovery (Carnarvon Petroleum 20%, Santos 80%) and TDO holds 100% interest in the permit. EXPLORATION RATIONALE Exploration in the Bedout Sub-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. Dorado 1 drilled in July 2018 fuelled a resurgence of exploration activity in the basin with the discovery of the largest oil field in Australia over the last 30 years. The discovery comprises 162 MMbbls of liquids and 748 Bcf of gas within multiple reservoirs of the Lower Triassic. Flow testing of the Dorado-3 appraisal well in September 2019 confirmed excellent reservoir quality, recording a maximum flow rate of 48 mscf/day of gas and 4,500 bbl/day of oil from the Baxter reservoir, while the Caley reservoir achieved flow rates up to 11,100 bbl/day oil and 21mcf/day associated gas (STO release, 8 Oct 2019). Flow rates from both intervals were constrained by surface equipment and are some of the best recorded on the Northwest Shelf of Australia. These are excellent results for reservoirs buried greater than 4000m depth. The Santos led Joint Venture has recently entered Front-End Engineering and Design (FEED) on a multi-phased development of Dorado Field, the first in the basin. A Final Investment Decision (FID) on Dorado Field is anticipated in mid-2022 and will ultimately establish the Bedout Sub-basin as Australia’s newest producing petroleum province. The Joint Venture has also just finalised the acquisition of the Archer 3D Marine Seismic Survey (MSS), which images the Dorado Field, as well as the Keraudren Extension 3D MSS which lies directly “The Sauropod 3D MSS will provide TDO the means to capitalise on its strategic early entry into what remains a highly underexplored basin” Figure 1 WA 527/P Location and Sea Floor Bathmetry adjacent to WA/527-P. These 3D seismic surveys will underpin a drilling campaign that is anticipated to span several years and will commence with the drilling of two exploration wells at Pavo and Apus prospects. These prospects have similar source, seal, trap, and reservoir characteristics to Dorado Field. The Dorado discovery supports TDO’s long held technical view that the region hosts a prolific petroleum system, previously overlooked by industry. The pre-Dorado acquisition of WA/527-P reflects TDO’s ability to recognize early opportunity and act ahead of our larger competitors. Importantly, Triassic targets within WA/527-P are likely to have up to 1000m less overburden than Dorado, and therefore, reservoir potential is anticipated to be similar, if not better. In addition, the potential for analogous Dorado-style stratigraphic traps also exists in WA/527-P. A system of erosional incised valleys has been identified on reprocessed legacy 2D seismic in the permit and will be fully appraised after the acquisition of 3D seismic data. 7 ACTIVITIES Throughout the year TDO has been engaged in negotiations with seismic contractors to secure a vessel to shoot the Sauropod 3D Marine Seismic Survey (MSS), in compliance with Year 3 work commitments. NOPSEMA approved TDOs Environment Plan (EP) in July 2020 and acquisition was planned between January and April 2021 inclusive. TDO was disappointed to miss the acquisition window due to protracted negotiations with seismic contractors but continues negotiations to ensure the timeline for the next available acquisition window. The Environmental Plan (EP) is in the process of being updated for the new acquisition window and will allow for a full fold acquisition area of ~3447 km2 of 3D seismic data. The survey is an integral next step in the exploration strategy for the permit and will have multiple objectives: — Delineation of any targets 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 legacy 2D seismic, including Salamander, Jaubert, and Whaleback; — Investigation of the potential Palaeozoic play interpreted on the eastern side of the acreage; and — Identification of any structures 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 The Sauropod 3D MSS is aptly named, as the key to unlocking the potentially significant prospectivity of the eastern flank of the basin through the definition of the northern extension of the Dorado play. The Sauropod 3D MSS will provide TDO the means to capitalise on its strategic early entry into what remains a highly underexplored basin. The existing 2D seismic data over the permit is sparse and not suitable for viewing hydrocarbon related seismic signatures, if visible. Recent 3D seismic acquisition in the basin using the latest imaging techniques and long offset streamer lengths has yielded a significant uplift in image quality. The Sauropod 3D MSS will enable TDO to develop a risked and ranked leads and prospects portfolio to attract favourable farm-in terms in fulfilment of the secondary term work program. TDO has continued its farmout campaign and hosted presentations and data rooms for numerous interested parties under difficult circumstances given the COVID-19 pandemic. 8 Figure 3 – WA/527-P Location, recent oil & gas discoveries, and Triassic erosional channel systems PROSPECTIVITY Mesozoic leads TDO has identified a series of structures along the western side of the acreage that may host Triassic sands like those encountered at Dorado and Roc. Trap types in the Triassic play include a combination of conventional faulted anticlines and possible stratigraphic traps sealed laterally by the incised valley 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 TDO 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 TDO has identified the presence of at least six reef-like features that could form viable oil targets, ranging in size from 3-30km2. These are mostly identified within the eastern side of the acreage, within what is interpreted as an extensive Palaeozoic Barrier Reef System. The extension of this system in the onshore Canning Basin is a proven petroleum system at the Blina and Ungani oil fields. 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 Resources Estimate (MMbbls) Recoverable Oil (ASX ann. 26/2/18) Lead/Prospect Salamander Jaubert Whaleback WA/527-P Total Status Lead Lead Lead Low 57 17 16 90 Best 191 72 87 High 713 205 219 350 1,137 9 Figure 5 – Otway Basin permits, fields and infrastructure relative to T/49-P 10 T/49P, OTWAY BASIN, OFFSHORE VICTORIA The primary objective of the survey is to image the existing leads in the central and southern areas of the permit with high quality 3D seismic, and to provide further technical insights on the Flanagan Prospect. This will enable the Joint Venture to develop a complete and consistent prospect seriatim to facilitate forward strategic decision making. COPA may elect to drill around the drilling of an exploration well following the interpretation of the survey in fulfilment of the Year 6 work commitment. In the event COPA elects to drill an exploration well, TDO will be carried for up to US$30M in drilling costs, for an exploration well, after which it will contribute 20% of drilling costs in line with its interest. The Joint Venture was pleased to receive regulatory approval for the Sequoia 3D MSS, with conditions and limitations, from NOPSEMA on 10 August 2021. At the time of writing this report, the Shearwater GeoCoral had Shearwater’s Geo Coral has commenced acquiring the initial lines of the survey, the first step towards realising the potential 10TCF perspectivity of the permit. TDO holds 20% interest in the T/49P exploration permit, which is operated by ConocoPhillips Australia SH1 Pty Ltd (COPA). The permit is situated west of King Island, Tasmania, and covers 4,960 km2 of the offshore Otway Basin. T/49-P 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 ~150,000 km2 along the southern margin of Australia. The basin has been an important supplier of gas to the east coast since the 1980s and the T/49-P permit is optimally placed to contribute much needed additional resources to this market. T/49-P is highly prospective for gas and contains numerous structures 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, with only 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. EXPLORATION RATIONALE TDO management believes the south-east Australian gas market will be strong in the coming years as existing gas production in both the Gippsland and Otway Basin declines. The National COVID-19 Response Coordination Commission has flagged the importance of securing additional gas supply to fuel industrial 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 support the uptake of renewable energy by filling gaps in the grid where renewable energy generation is intermittent. TDO recognised the potential for the shortfall in gas supply to south-east Australia as early as 2012 and acquired the T/49-P exploration permit on that basis. The wider industry now shares the view that the region contains significant yet-to-find gas. As a result, there is significant exploration activity in the basin. In August 2019, Cooper Energy Ltd (ASX: COE) drilled Annie-1 resulting in the first offshore gas discovery in the Otway Basin in 11 years. Beach Energy Ltd (ASX: BPT) discovered gas at Enterprise 1 in November 2020 and has recently kicked-off plans to drill up to 8 wells between 2021 and 2023. The first of these, the Artisan 1 exploration well, was drilled in March 2021 and resulted in a gas discovery consistent with pre-drill estimates. A series of appraisal and/or development wells will be drilled by Beach Energy Ltd in the following campaign at Thylacine, Geographe, and potentially La Bella, along with the installation of subsea infrastructure to tie-in wells to the existing platform and infrastructure. Yet another compelling indication of the importance of the Otway Basin is the entrance of COPA, by way of farm-in to TDO’s T/49-P exploration permit. ACTIVITIES The National Offshore Petroleum Titles Administrator (NOPTA) approved the farmout of 80% interest in T/49-P to COPA on 9 June 2020. This event signified an important step forward in TDO's strategy to discover commercial gas in southeast Australia and help mitigate the upcoming supply shortfall to the local market. Since transferring operatorship to COPA, the Joint Venture commenced acquisition of the Sequoia 3D Marine Seismic Survey (MSS), formerly the Dorrigo MSS, covering an area of ~2500 km2. This represents a substantial increase from the minimum requirement as per the Farmout Agreement (“FOA”) and ensures most of the permit will be covered with high quality 3D seismic that leverages the latest advances in acquisition and processing technology. “TDO recognized the potential for the shortfall in gas supply to south-east Australia as early as 2012 and acquired the T/49-P exploration permit on that basis” 11 Figure 6 – Modelled gas expulsion and migration PROSPECTIVITY TDO acquired T/49-P due to its unique position within respect to the regional structural configuration of the southern Otway Basin. The permit is located along the edge of a paleo-shelf break, the depositional focus of a series of thick progradational clinoforms over the last 35 Million Years. These clinoforms have resulted in rapid loading of the proven sources rocks in this section of the Otway Basin. TDO is of the belief that this mechanism is responsible for providing gas of the largest offshore Otway Basin gas fields, Thylacine and Geographe, and is likely to contribute hydrocarbons to the leads and prospects of T/49-P (Figure 6). Flanagan Prospect Flanagan is a ‘drill ready’ prospect located in shallow water and defined by the Flanagan 3D MSS, acquired in 2014. The structure has a maximum aerial closure of approximately 80 km2 and is ideally located adjacent to multiple source kitchens. The prospect has a best estimate prospective resource of 1.34 TCF (announced 27 July 2017) and is the closest drill target to existing infrastructure at Thylacine and Geographe fields. 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. 12 Figure 7 – Seismic Interpretation and high amplitude zones at the Seal Rocks lead Seal Rocks Lead Located in the south of the permit and at an analogous shelf-break location to Thylacine Field, one of the key objectives of the upcoming Sequoia 3D MSS is the Seal Rocks lead (Figure 7). In 2019 TDO completed reprocessing and interpretation of legacy 2D seismic and defined the presence of several high amplitude zones, likely to represent good quality reservoir sands (Figure 7). These reservoirs appear to fit a series of tilted fault-blocks, and while the reprocessed 2D seismic has provided a more accurate understanding of the structure at Seal Rocks, 3D seismic is required to determine the true resource potential of the structure. Table 2: T/49P Prospective Resource Estimate (TCF) Recoverable Gas (ASX ann. 27-Jul-17) Lead/Prospect Flanagan Munro (T/49P Part) Whistler Point British Admiral Seal Rocks Harbinger T/49P Total Status Prospect Lead Lead Lead Lead Lead Low 0.53 0.04 0.82 0.37 0.95 0.33 Best 1.34 0.19 2.04 1.03 4.64 0.79 High 2.74 0.57 8.95 4.45 10.64 1.43 3.04 10.03 28.78 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. “TDO completed reprocessing and interpretation of legacy 2D seismic and defined the presence of several high amplitude zones” 13 Figure 8 – VIC/P57 location (green) with area of reprocessed 3D seismic data (blue polygon). Inset map shows permit locations relative to the Gippsland Basin.’ VIC/P57, GIPPSLAND BASIN OFFSHORE VICTORIA Exploration Permit VIC/P57 lies in the northwest offshore Gippsland Basin within shallow waters close to shore (Figure 8). TDO holds a 24.9% interest in VIC/P57 and, by arrangement with operator Carnarvon Hibiscus Pty Ltd (CHPL), continues to carry out subsurface technical work on behalf of the Joint Venture. VIC/P57 covers an area of 246 km2 and is located proximal to existing infrastructure. The permit was renewed by TDO and Carnarvon Hibiscus Pty Ltd (CHPL) in 2018 for a further five years. As a part of this process the Joint Venture was required to relinquish non prospective graticular blocks and has retained the most valuable acreage. EXPLORATION RATIONALE The Gippsland Basin is Australia’s most prolific oil and gas producing basin, with initial reserves estimated at 4 billion barrels of oil and 11.5 trillion cubic feet of gas. Twenty-one oil and gas fields are on production with most of the hydrocarbons hosted by the world-class sandstones of the upper Latrobe Group. The Gippsland Basin is considered extremely important for gas supply to southeast Australia, providing around 40% of all gas used in eastern Australia and 80% of Victoria’s gas over winter (ExxonMobil). However, production is in decline and the Australian Energy Market Operator (AEMO) 14 Gas Statement of Opportunities, released in March 2021, suggests that southern gas fields have declined faster than anticipated, with the last major southern gas field expected to deplete before winter 2023. The A$400M West Barracouta development delivered first gas to the east coast market in April 2021 with the successful drilling of two gas production wells and installation of subsea production facilities. Several important events have occurred over the course of the year that have implications for future exploration and production in the basin. Having announced in September 2019 an intent to divest Bass Strait assets, ExxonMobil Corporation (NYSE: XOM) abandoned their multi-billion-dollar sale in November 2020, shortly after their deadline for indicative bids, citing an extensive portfolio and market re-evaluation. Furthermore, at the time of writing this report, BHP Group Ltd (BHP) (50% partner in Bass Strait) announced a merger with Woodside Petroleum Ltd (ASX: WPL) to form a top 10 global independent energy company. While the forward impact of these events on the Gippsland Basin remains unclear, it seems likely there will be near term opportunities for small agile companies such as TDO. The A$400M West Barracouta development delivered first gas to the east coast market in April 2021 with the successful drilling of two gas production wells and installation of subsea production facilities. A major milestone was achieved in early 2021 with the delivery of fast-tracked results from CGG’s basin scale multiclient 3D seismic acquisition in 2020, covering some 12,000 km2. This dataset will play a key role in unlocking a new wave of exploration in the basin, leveraging the latest acquisition and processing technology to deliver a significant uplift in image quality of deeper, non-traditional plays such as the Golden Beach and Emperor Subgroups. TDO believes that there are significant resources remaining in the Gippsland Basin, with many plays remaining underexplored. Innovative exploration leveraging the latest reprocessing and acquisition techniques is central to TDO’s strategy to identify previously overlooked opportunities in the basin. Moreover, the Gippsland 3D MSS covers several of TDO’s major leads and prospects, including Felix (VIC/P57) and Bigfin (VIC/P74). Given the major role Gippsland gas plays in the east coast gas market, the newly acquired Gippsland 3D MSS will underpin the future security of gas supply to south-east Australia. TDO is well positioned with its near-term and drill-ready Gippsland Basin exploration assets to take advantage of the predicted gas shortfall over the coming 5 years, especially given the emphasis on a gas led COVID-19 economic recovery. ACTIVITIES VIC/P57 entered the final year of the Primary Term on 7 March 2020. TDO applied for a 12-month Suspension and Extension to the Primary Term of VIC/P57, which has received approval from the NOPTA, extending the Primary Term to 6 March 2022. 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. “Innovative exploration leveraging the latest reprocessing and acquisition techniques is central to TDO’s strategy to identify previously overlooked opportunities in the basin” Two drilling candidates have been identified in the permit, including Felix and Pointer. Pointer Prospect is the largest drill target in the permit and was initially resolved on legacy 3D seismic during amplitude screening. It has since been matured to drill ready status using multiclient 3D seismic reprocessing. An AVO supported gas prospect with proximity to shore and infrastructure, Pointer is well placed to supply gas to the east coast market. Dexter is located down-dip and along strike to Pointer and has been confirmed as a strong lead. Exploration success at Pointer would reduce geological uncertainties at Dexter, which represents valuable additional potential for the permit. Felix is a low-risk Oil & Gas prospect located between the Wirrah and Moonfish discoveries. Excellent local well control provides an excellent understanding of the petroleum system and significantly de-risks the prospect. Over the course of the year TDO has continued its farmout campaign to support the drilling of one of these drill ready prospects, hosting data rooms for numerous interested parties. The low risk profile of Felix and the potential for Pointer to provide low-cost gas to the domestic market is recognized by industry. Figure 9 – Arbitrary seismic line through Wirrah Discovery, Felix Prospect and Moonfish Field (Image courtesy of CGG Multiclient & New Ventures) PROSPECTIVITY Felix Prospect Felix Prospect is an inversion anticline favourably situated between the Moonfish and Wirrah discoveries along the Seahorse Fault. (Figure 9). 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, TDO understands 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. 15 Figure 10 – Pointer Prospect Amplitude Anomaly (image courtesy of CGG Multiclient & New Ventures) Pointer Prospect Pointer Prospect is a combination structural-stratigraphic trap 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 10) 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 a low-cost development for the domestic gas market. Table 3: Total VIC/P57 Prospective Resources Estimate (MMbbls) Recoverable Oil (ASX ann. 27/7/17) Lead/Prospect Felix Salsa VIC/P57 Total Status Prospect Lead Low 6.8 10.7 17.5 Best 15.9 15.1 High 26.9 20.6 31.0 47.5 Table 4: Total VIC/P57 Prospective Resource Estimate (BCF) Recoverable Gas (ASX ann. 27/7/17) Location Pointer Dexter Status Prospect Lead Low 140.1 37.0 Best 235.3 132.0 High 364.9 259.1 VIC/P57 Total 177.1 367.3 624.0 “The prospect shows a clear rising amplitude with offset response, a Class III AVO which is likely to represent dry gas” 16 Figure 11 – VIC/P74 Location VIC/P74, GIPPSLAND BASIN OFFSHORE VICTORIA Located in the Offshore Gippsland Basin, VIC/P74 was awarded to TDO on 26 July 2019 by the NOPTA. The permit covers 1,006 km2 of the shallow continental shelf with water depths ranging up to 70m. Geologically, the permit straddles the boundary of the Southern Terrace and the Central Deep on the southern flank of the Gippsland Basin. VIC/P74 is ideally situated, flanking several important discoveries in the basin (Figure 11). Kingfish Field, the largest oil field in Australia, lies 5km to the east and has produced over 1 billion barrels from the classic top Latrobe play. Likewise, Bream Field lies 5km to the north and represents a significant gas-condensate discovery within the same play. An exploration campaign in the 1980s by former operator Aquitane yielded the first and only discovery inside the permit, consisting of gas condensate within the lower Latrobe Group at Omeo Field – a three-way downside dip closure located adjacent to newly discovered leads against the Southern Terrace. EXPLORATION RATIONALE Exploration well post-mortems completed by TDO identified that several well failures in VIC/P74 can be attributed to trap presence, owing to drilling on coarse legacy 2D seismic, as well as depth conversion issues caused by velocity anomalies in the shallow overburden. VIC/P57 on the northern flank of the basin has the same velocity issues, however, TDO has significantly enhanced depth models by licencing CGG’s 3D seismic reprocessing over VIC/P57. TDO observed a significant uplift in seismic quality and velocities, which has enhanced the accuracy of depth models over Felix Prospect and supported the maturation of Pointer Prospect. TDOs exploration rationale in acquiring VIC/P74 was to licence the CGG multiclient 3D seismic reprocessing to exploit recent advances in reprocessing techniques and resolve previously missed traps within a prolific petroleum system. ACTIVITIES TDO has rapidly advanced the VIC/P74 work program over the course of the year, despite the impacts of the COVID-19 pandemic. VIC/P74 entered Year 2 of the primary work program on 26 July 2020. TDO fulfilled a major work commitment of the primary term in August 2020 by licencing 1,004 km2 of the CGG multiclient 3D reprocessing, including full and offsets stacks, gathers, and a velocity cube. In October 2020, TDO progressed its strategy to fund exploration activities through strategic partnerships, with NOPTA approving the formation of a Joint Venture (JV) with Carnarvon Hibiscus Pty Ltd (“CHPL”), a wholly owned subsidiary of Hibiscus Petroleum Berhad. Under the terms of the Joint Operating Agreement, TDO retained operatorship with 50% equity in the permit. 17 Figure 12 – Comparison between legacy and CGG 3D reprocessed seismic at Bigfin Lead Figure 13 – Top Golden Beach Subgroup depth map with identified closures (purple outlines) have additional smaller closures within overlying upper Latrobe Group reservoirs, which are likely oil prone. Stargazer represents an untested play type in the basin as a stratigraphic pinch-out onto the Strzelecki Group of the Southern Terrace, which forms a proven cross-fault seal at Longtom Field. Additional gas prospectivity is currently under assessment within the deeper Emperor Subgroup play with a view to updating the current prospective resource estimates. Encouragingly, TDO has been approached by several interested parties over the course of the year, and despite the impacts of COVID, has hosted numerous presentations and virtual data rooms. The Joint Venture is seeking the best possible terms to facilitate the next stages of exploration, including seismic acquisition and drilling. Over the course of the year the Joint Venture has fully interpreted the newly licenced reprocessing, which has provided a significant uplift in data quality (Figure 12). Twelve key seismic horizons were interpreted across the shallow overburden, upper Latrobe Group, and prospective Golden Beach and Emperor subgroups within the lower Latrobe Group. Mapping of the shallow overburden was particularly important for constraining shallow interval velocities, as previous drilling failures in the permit have been attributed to depth conversion error caused by complex velocity inversions within the overburden. The velocity cube from the newly reprocessed 3D seismic provides unprecedented resolution of these inversions. gas-condensate prospectivity through the presence of major structural and stratigraphic traps (Figure 13). Closures are supported by detailed depth conversion studies, including comprehensive sensitivity analysis underpinned by a range of depth conversion techniques. On 16 February 2021, TDO released a leads inventory with prospective resource estimates to the market, validating the original strategy in acquiring VIC/P74. At least four leads are considered prospective for gas-condensate within the Golden Beach Subgroup. The largest of the identified leads is Bigfin, located in the northeast corner of the permit, which has a Best Estimate recoverable volume of 534 Bcf (502 Bcf in permit). A series of structures with small oil-prone closures across several Upper Latrobe reservoirs have been identified, however, deeper mapping of the top Golden Beach Subgroup reservoir revealed significant Stargazer, Oarfish, and Megatooth leads flank the Southern Terrace and have a combined Best Estimate prospective resource of 785 Bcf and 27 MMbbls condensate. Megatooth and Oarfish leads 18 PROSPECTIVITY Bigfin Lead Bigfin is a faulted anticline at the top Golden Beach Subgroup with a target drilling depth of ~2950m TVDSS. Bigfin lies directly adjacent to the world class Kingfish structure and has a large areal closure (~29km2) and vertical relief (up to 230m). Bigfin is ideally located with respect to established production infrastructure at nearby Bream Field, where production is currently suspended, and lies in shallow water depths of ~80m. Given the large size of the closure, the structure has a commercial Best Estimate gas volume of 534 Bcf (502 Bcf in permit). The overlying structure was tested in 1969 by Gurnard-1, a dry hole that recovered an oil show from formation water in the overlying F.longus reservoir. Well failure at the primary Top Latrobe objective is attributed to a lack of cross-fault seal. Gurnard 1 did not intersect the underlying Golden Beach section, which TDO estimates could hold as much as 783 Bcf and 38.6 MMbbls in the high estimate. Paleogeographic maps indicate these resources will likely be hosted by coastal plain sands top sealed by Campanian aged volcanics, which have been intersected in nearby offset wells, including the Omeo wells, Speke 1, and Melville 1. Volcanics are proven to form a competent top seal at analogous producing fields in the basin, including Kipper and Manta. The structure has a large throw and relies on cross-fault seal with the F.longus lower coastal plain, consisting of interbedded shales, siltstones and coals. Volcanic intrusions within fault planes form important cross-fault seals for fields along the margin of the Northern Terrace and may also provide an additional cross-fault sealing mechanism at Bigfin, given the presence of local intrusive volcanics. The structure has a large throw and relies on cross-fault seal with the F.longus lower coastal plain, consisting of interbedded shales, siltstones and coals. Volcanic intrusions within fault planes form important cross-fault seals for fields along the margin of the Northern Terrace and may also provide an additional cross-fault sealing mechanism at Bigfin, given the presence of local intrusive volcanics. Table 1: VIC/P74 Prospective Resources Estimate (Bcf) Recoverable Gas (Nett to TDO in brackets) (ASX ann. 16-Feb-21) Lead/Prospect Bigfin Stargazer Oarfish Megatooth Status Lead Lead Lead Lead Low Best High 296 (148) 502 (251) 783 (392) 192 (96) 344 (172) 564 (282) 132(66) 237 (119) 400 (200) 114 (57) 204 (102) 345 (173) VIC/P74 Total 734 (367) 1287 (644) 2092 (1047) Table 2: VIC/P74 Prospective Resources Estimate (MMbbls) Recoverable Condensate (Nett to TDO in brackets) (ASX ann. 16-Feb-21) Lead/Prospect Bigfin Stargazer Oarfish Megatooth VIC/P74 Total Status Lead Lead Lead Lead Low 2 (1) 3 (1.5) 2 (1) 1.7 (0.85) Best 19 (10) 12 (6) 8 (4) 7 (3.5) High 39 (20) 37 (19) 26 (13) 22 (11) 9 (4) 46 (24) 124 (63) Table 3: VIC/P74 Prospective Resources Estimate (MMbbls) Recoverable Oil (Nett to TDO in brackets) (ASX ann. 16-Feb-21) Lead/Prospect Megatooth Oarfish VIC/P74 Total Status Lead Lead Low 28 (14) 23 (11) Best 58 (29) 40 (20) High 107 (54) 71 (35) 51 (25) 98 (49) 178 (89) “The largest of the identified leads is Bigfin, located in the northeast corner of the permit, which has a Best Estimate recoverable volume of 534 Bcf (502 Bcf in permit)” 19 DIRECTORS’ REP ORT 20 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 2021. 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 Consolidated Entity 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 $1,142,095 (30 June 2020: $3,006,065). Refer to the detailed Review of Operations preceding this Directors' Report. FINANCIAL POSITION The net assets decreased by $1,133,023 to $7,609,520 at 30 June 2021 (30 June 2021: $8,742,543). During the year the Consolidated Entity spent a net amount after reimbursements of $851,721 (2020: $726,453) on exploration, mainly in relation to WA/527P, T49/P and VIC/P74 during the year. The working capital position of the Consolidated Entity as at 30 June 2021 is $2,067,184 (30 June 2020: $4,033,946). The Consolidated Entity incurred net operating cash outflows of $1,048,675 (2020: $980,209). The cash balance as at 30 June 2021 was $3,048,802 (2020: $5,077,191). Based on the above the Directors believe the Consolidated Entity is in a position to continue to pursue its current operational objectives. SIGNIFICANT CHANGES IN THE STATE OF AFFAIRS On 14 July 2020, the Consolidated Entity 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. On 9 October 2020, the Consolidated Entity announced that the NOPTA approved Hibiscus Petroleum Berhad to enter into a Joint Venture with TDO in the offshore Gippsland Basin exploration permit VIC/P74. Under the terms of the Assignment Agreement, TDO will remain as operator with 50% equity. On 16 December 2020, the Consolidated Entity announced the issue of 225,806 Performance Rights to Directors of the Company, with Mr Leo De Maria receiving 112,903 Performance Rights and Mr Ian Tchacos each receiving 112,903 Performance Rights, following shareholder approval at the Company’s Annual General Meeting on 17 November 2020. Vesting of the Performance Rights is contingent on both the share price of the Company reaching $0.09 (9 cents) at any time between grant date and 17 November 2022 and continued employment through 17 November 2022. The Performance Rights expire 3 years following the grant date. On 15 February 2021, the Consolidated Entity announced the issue of 516,128 Performance Rights to eligible employees under the Consolidated Entity's Equity Incentive Plan. Vesting of the Performance Rights is contingent on both the share price of the Company reaching $0.09 (9 cents) at any time between grant date and 17 November 2022 and continued employment through 17 November 2022. The performance rights expire 3 years following their grant date. On 16 February 2021, the Consolidated Entity announced that a series of Leads with a total Best Estimate Prospective Resource of 370 MMboe have been delineated by interpretation of newly reprocessed seismic data and the completion of detailed depth conversion studies. The largest is the Bigfin Lead which is hosted within the Lower Latrobe Group and has a Best Estimate Prospective Resource of 502 Bcf and 19 MMbbls of condensate. Bigfin is located approximately 8km West of the Kingfish Oil Field which has produced over 1 billion bbls to date. An additional three Leads also hosted by the Lower Latrobe Group have a total Best Estimate Prospective Resource of 785 Bcf gas. Two of these Leads are also considered prospective for oil within the Upper Latrobe Group with a combined Best Estimate Prospective Resource of 98 MMbbls. On 1 March 2021, the Consolidated Entity announced that TDO’s wholly owned subsidiary, 3D Oil T49P Pty Ltd, together with its partner in T/49P, ConocoPhillips Australia SH1 Pty Ltd (“COP”), has contracted the Shearwater vessel the Geo Coral to acquire the Sequoia 3D seismic survey. 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 In accordance with the announcement of 1 March 2021, the Consolidated Entity announced on 11 August 2021 that ConocoPhillips Australia SH1 Pty Ltd (“ConocoPhillips Australia”) as operator of the T/49P joint venture with TDO’s wholly owned subsidiary, 3D Oil T49P Pty Ltd, will commence acquisition of the Sequoia MSS 3D seismic survey using the Shearwater vessel the Geo Coral. The survey is planned to cover an area of approximately 2,500 km2 with the seismic survey acquisition estimated to take approximately 60 days between the middle of August and the end of October 2021. ConocoPhillips Australia is the operator of the T/49P joint venture with an 80% interest in the T/49P Permit, the Company having the remaining 20% interest. Under the terms of the Farmout Agreement, ConocoPhillips Australia was to acquire a minimum of 1580 km2 of 3D seismic at no expense to the Company (TDO ASX Announcement 11 June 2020). The proposed increase in size of the acquisition area will provide coverage of all leads within the T/49P Permit and tie in with the previously acquired Flanagan 3D seismic survey. No other matter or circumstance has arisen since 30 June 2021 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. 21 LIKELY DEVELOPMENTS AND EXPECTED RESULTS FROM OPERATIONS The Consolidated Entity will continue to pursue its exploration interest in — VIC/P57 and VIC/P74 in partnership with Carnarvon Hibiscus Pty Ltd; — T49P in partnership with Conoco Phillips Australia SH1 Pty Ltd; — WA/527-P in the Roebuck Basin of Western Australia. In July and August 2021, the Australian economy has experienced disruption related to COVID 19 triggered, Statewide lockdowns across all major States including New South Wales, Victoria and Queensland. These lockdowns have caused disruption to the broader business community and the Australian mining and exploration industry's operations have not been immune. There is significant uncertainty around the breadth and duration of business disruptions related to COVID-19 and therefore the Consolidated Entity has taken precautionary measures by temporarily closing the Consolidated Entity’s office and having arranged for the employees to work remotely, as well as curtailing travel. Management believes that this will allow the continuance of its current principal business activities. At the date of this report, the impact of these measures is not expected to significantly impact the completion of the activities currently being undertaken. However, as the circumstances continue to evolve, there may be disruptions to future activities, 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. 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 2021. 22 INFORMATION ON DIRECTORS Mr Noel Newell Executive Chairman Mr Leo De Maria Non-Executive Director Qualifications B App Sc (App Geol) Experience and expertise Noel Newell holds a Bachelor of Applied Science and has over 30 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 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 the Audit and the Remuneration and Nomination Committees Interests in shares 650,070 ordinary fully paid shares. Interests in options None Interests in rights 112,903 performance rights 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 the Audit Committee and the Remuneration and Nomination Committee Interests in shares 428,500 ordinary fully paid shares Interests in options None Interests in rights 112,903 performance rights 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 BBus (Acc) Joint Company Secretary Mr Stefan Ross has over 12 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. Mr Ross graduated from ACU in 2008 obtaining a Bachelor of Business majoring in Accounting. MEETINGS OF DIRECTORS The number of meetings of the Company's Board of Directors ('the Board') held during the year ended 30 June 2021, and the number of meetings attended by each Director were: Meetings Held Meetings Attended 6 6 6 6 6 6 Mr N Newell Mr L De Maria Mr I Tchacos Held: represents the number of meetings held during the time the Director held office. 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 '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. 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. 23 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. 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 its cost to the Consolidated Entity and expensed. Options and performance rights are valued using the Hoadley Trading & Investment Tools (“Hoadley”) ESO5 option valuation model. The long-term incentives ('LTI') includes long service leave and share-based payments. Shares, options or performance rights are awarded to executives on the discretion of the Board based on long-term incentive measures. Consolidated Entity performance and link to remuneration Commencing in the 2021 financial year, Directors and employees' remuneration packages include performance-based components. Performance rights may be granted which offer the recipient the right, upon achieving predetermined milestones, to participate in the benefits accruing to shareholders through the alignment of the terms of the performance rights to the shareholders' interests. During the year ended 30 June 2021, the Company granted performance rights which are conditional upon the achievement of a target share price and tenure of employment. The intention of this program is to facilitate goal congruence between Directors, Executives and employees 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 17 November 2020 Annual General Meeting ('AGM') The Company received 92.73% of 'for' votes in relation to its remuneration report for the year ended 30 June 2020. The Company did not receive any specific feedback at the AGM regarding its remuneration practices. 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, statutory entitlements including superannuation, annual leave and long service leave and cash bonuses; and — share-based payments 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. 24 Short-term benefits Short term incentives Post- employment benefits Long-term benefits Equity settled share based payments Salaries and fees Cash bonus Super- annuation Long service leave Performance rights 2021 Non-Executive Directors: Mr I Tchacos Mr L De Maria Executive Directors: Mr N Newell 2020 Non-Executive Directors: Mr I Tchacos Mr L De Maria Executive Directors: Mr N Newell $ - - 6,752 6,752 $ - - $ 43,151 41,096 $ - - $ 4,099 3,904 350,794 50,000 21,694 435,041 50,000 29,697 $ 4,099 3,904 $ 43,151 41,096 353,180 437,427 $ - - - - 23,275 14,414 31,278 14,414 Total $ 48,847 46,597 $ 1,597 1,597 - 429,240 3,194 524,684 $ - - - - $ 47,250 45,000 390,869 483,119 The proportion of remuneration linked to performance and the fixed proportion are as follows: Name Non-Executive Directors: Mr I Tchacos Mr L De Maria Executive Directors: Mr N Newell Fixed remuneration At-risk short term remuneration At-risk long term remuneration 2021 2020 2021 2020 2021 2020 97% 97% 100% 100% - - 89% 100% 11% - - - 3% 3% - - - - 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 (i) Mr Newell may resign from his position and thus terminate this contract by giving 6 months written notice. Mr Newell is only entitled to that portion of remuneration which is fixed, and only up to the date of termination. (ii) The Company may terminate this (iv) On termination of the agreement, employment agreement by providing 6 months written notice. (iii) The Company may terminate the Mr Newell will be entitled to be paid those outstanding amount owing to him up until the Termination date. contract at any time without notice if serious misconduct has occurred. Where termination with cause occurs, Key management personnel have no entitlement to termination payments in the event of removal for misconduct. 25 SHARE-BASED COMPENSATION Issue of shares The Company issued nil (2020: nil) shares to directors and key management personnel as part of compensation during the year ended 30 June 2021. 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 2021 (2020: Nil). Performance rights There were 225,806 performance rights over ordinary shares issued to Directors as part of compensation that were outstanding as at 30 June 2021 (2020: Nil). Grant date 17 November 2020 Vesting date and exercisable date Expiry date Share price hurdle for vesting Fair value per right at grant date 17 November 2022 17 November 2023 $0.090 $0.046 Name Number of rights granted Grant date Vesting date and exercisable date Expiry date Mr Ian Tchacos 112,903 17 November 2020 17 November 2022 17 November 2023 Mr Leo De maria 112,903 17 November 2020 17 November 2022 17 November 2023 Share price hurdle for vesting Fair value per right at grant date $0.090 $0.090 $0.046 $0.046 Performance rights granted carry no dividend or voting rights. No performance rights vested and were exercised during the year. Additional information The earnings of the Consolidated Entity for the five years to 30 June 2021 are summarised below: 2021 $ 2020 $ 2019 $ 2018 $ 2017 $ Other income including interest income 87,478 85,279 43,629 27,696 14,677 Net loss before tax Net loss after tax (1,142,095) (3,006,065) (1,089,254) (1,154,810) (1,839,978) (1,142,095) (3,006,065) (1,089,254) (1,154,810) (1,839,978) The factors that are considered to affect total shareholders return ('TSR') are summarised below: Share price at financial year start ($) Share price at financial year end ($) Basic loss per share (cents per share) 2021 0.07 0.05 (0.43) 2020 0.11 0.07 (1.13) 2019 0.05 0.11 (0.42) 2018 0.04 0.05 (0.49) 2017 0.02 0.04 (0.77) 26 Additional disclosures relating to key management personnel Shareholding The number of shares in the Company held during the financial year by each Director and other members of key management personnel of the Consolidated Entity, including their related parties, is set out below: Ordinary shares Mr N Newell Mr L De Maria Mr I Tchacos Performance rights holding The number of performance rights over ordinary shares in the Company held during the financial year by each Director of the Consolidated Entity, including their related parties, is set out below: Performance rights over ordinary shares Mr L De Maria Mr I Tchacos This concludes the remuneration report, which has been audited. Balance at the start of the year Received as part of remuneration Additions Disposals/ other 44,192,229 650,070 428,500 45,270,799 - - - - - - - - - - - - Balance at the end of the year 44,192,229 650,070 428,500 45,270,799 Balance at the start of the year Granted Vested Expired/ forfeited/ other Balance at the end of the year - - - 112,903 112,903 225,806 - - - - - - 112,903 112,903 225,806 27 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 Unissued ordinary shares of 3D Oil Limited under performance rights at the date of this report are as follows: Grant date 17 November 2020 28 January 2021 29 January 2021 1 February 2021 11 February 2021 Expiry date 17 November 2023 17 November 2023 17 November 2023 17 November 2023 17 November 2023 No person entitled to exercise the performance rights had or has any right by virtue of the performance right to participate in any share issue of the Company or of any other body corporate. 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 2021 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 2021. 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. This report is made in accordance with a resolution of Directors, pursuant to section 306(3)(a) of the Corporations Act 2001. Auditor Grant Thornton Audit Pty Ltd continues in office in accordance with section 327 of the Corporations Act 2001. Exercise price Number under rights $0.000 $0.000 $0.000 $0.000 $0.000 225,806 80,645 80,645 112,903 241,935 741,934 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. Forward looking statements This Financial Report includes certain forward-looking statements that have been based on current expectations about future acts, events and circumstances. These forward-looking statements are, however, subject to risks, uncertainties and assumptions that could cause those acts, events and circumstances to differ materially from the expectations described in such forward-looking statements. These factors include, among other things, commercial and other risks associated with the meeting of objectives and other investment considerations, as well as other matters not yet known to the Company or not currently considered material by the Company. 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 23 September 2021 Melbourne 28 [This page has intentionally been left blank for the insertion of the auditor's independence declaration] 29 Grant Thornton Audit Pty Ltd ACN 130 913 594 a subsidiary or related entity of Grant Thornton Australia Ltd ABN 41 127 556 389 ‘Grant Thornton’ refers to the brand under which the Grant Thornton member firms provide assurance, tax and advisory services to their clients and/or refers to one or more member firms, as the context requires. Grant Thornton Australia Ltd is a member firm of Grant Thornton International Ltd (GTIL). GTIL and the member firms are not a worldwide partnership. GTIL and each member firm is a separate legal entity. Services are delivered by the member firms. GTIL does not provide services to clients. GTIL and its member firms are not agents of, and do not obligate one another and are not liable for one another’s acts or omissions. In the Australian context only, the use of the term ‘Grant Thornton’ may refer to Grant Thornton Australia Limited ABN 41 127 556 389 and its Australian subsidiaries and related entities. GTIL is not an Australian related entity to Grant Thornton Australia Limited. Liability limited by a scheme approved under Professional Standards Legislation. www.grantthornton.com.au Collins Square, Tower 5 727 Collins Street Melbourne Victoria 3008 Correspondence to: GPO Box 4736 Melbourne VIC 3001 T +61 3 8320 2222 F +61 3 8320 2200 E info.vic@au.gt.com W www.grantthornton.com.au Auditor’s Independence Declaration To the Directors of 3D Oil Limited In accordance with the requirements of section 307C of the Corporations Act 2001, as lead auditor for the audit of 3D Oil Limited for the year ended 30 June 2021, I declare that, to the best of my knowledge and belief, there have been: a no contraventions of the auditor independence requirements of the Corporations Act 2001 in relation to the audit; and b no contraventions of any applicable code of professional conduct in relation to the audit. Grant Thornton Audit Pty Ltd Chartered Accountants D G Ng Partner – Audit & Assurance Melbourne, 23 September 2021 FI NA NCIAL REP ORTS 30 CONSOLIDATED STATEMENT OF PROFIT OR LOSS AND OTHER COMPREHENSIVE INCOME For the year ended 30 June 2021 Other income Interest income Expenses Corporate expenses Employment expenses Occupancy expenses Depreciation and amortisation expense Impairment of exploration assets Exploration costs Share based payments Finance costs Loss before income tax expense Income tax expense Consolidated 2020 $ 75,873 9,406 2021 $ 82,908 4,570 (451,925) (572,794) (563,528) (471,800) (43,954) (34,427) (118,136) (110,207) - (1,886,343) (33,088) (9,072) (9,870) - - (15,773) (1,142,095) (3,006,065) - - Note 5 6 14 14 6 7 Loss after income tax expense for the year attributable to the owners of 3D Oil Limited (1,142,095) (3,006,065) Other comprehensive income for the year, net of tax - - Total comprehensive income for the year attributable to the owners of 3D Oil Limited (1,142,095) (3,006,065) Basic earnings per share Diluted earnings per share 31 31 Cents (0.43) (0.43) Cents (1.13) (1.13) The above consolidated statement of profit or loss and other comprehensive income should be read in conjunction with the accompanying notes 31 CONSOLIDATED STATEMENT OF FINANCIAL POSITION As at 30 June 2021 Assets Current assets Cash and cash equivalents Other receivables Short term investments Prepayments Total current assets Non-current assets Property, plant and equipment Right-of-use assets Intangibles Exploration and evaluation Total non-current assets Total assets Liabilities Current liabilities Trade and other payables Lease liabilities Employee benefits Total current liabilities Non-current liabilities Lease liabilities Employee benefits Total non-current liabilities Total liabilities Net assets Equity Issued capital Reserves Accumulated losses Total equity Note Consolidated 2021 $ 2020 $ 8 9 10 11 12 13 14 15 20 16 20 17 3,048,802 5,077,191 31,752 93,577 41,924 8,216 93,577 39,447 3,216,055 5,218,431 16,525 79,156 76,641 14,031 165,496 74,068 5,374,599 4,546,537 5,546,921 4,800,132 8,762,976 10,018,563 820,345 96,614 231,912 934,177 102,039 148,269 1,148,871 1,184,485 - 4,585 4,585 85,705 5,830 91,535 1,153,456 1,276,020 7,609,520 8,742,543 18 55,483,678 55,483,678 9,072 - (47,883,230) (46,741,135) 7,609,520 8,742,543 The above consolidated statement of profit or loss and other comprehensive income should be read in conjunction with the accompanying notes 32 CONSOLIDATED STATEMENT OF CHANGES IN EQUITY For the year ended 30 June 2021 Consolidated Balance at 1 July 2019 Contributed equity Accumulated losses $ $ 55,483,678 (43,740,935) Adjustment from adoption of AASB 16 - 5,865 Balance at 1 July 2019 – restated 55,483,678 (43,735,070) Reserves Total equity $ - - - - - - $ 11,742,743 5,865 11,748,608 (3,006,065) - (3,006,065) 8,742,543 Reserves Total equity $ - - - - $ 8,742,543 (1,142,095) - (1,142,095) - - - (3,006,065) - (3,006,065) 55,483,678 (46,741,135) Contributed equity Accumulated losses $ $ 55,483,678 (46,741,135) (1,142,095) - (1,142,095) - - - - Loss after income tax expense for the year Other comprehensive income for the year, net of tax Total comprehensive income for the year Balance at 30 June 2020 Consolidated Balance at 1 July 2020 Loss after income tax expense for the year Other comprehensive income for the year, net of tax Total comprehensive income for the year Transactions with owners in their capacity as owners: Share-based payments Balance at 30 June 2021 - 9,072 9,072 55,483,678 (47,883,230) 9,072 7,609,520 The above consolidated statement of profit or loss and other comprehensive income should be read in conjunction with the accompanying notes 33 CONSOLIDATED STATEMENT OF CASH FLOWS For the year ended 30 June 2021 Cash flows from operating activities Payments to suppliers and employees (inclusive of GST) Interest received Interest on lease liabilities paid COVID-19 incentives Note Consolidated 2021 $ 2020 $ (1,132,676) (1,058,349) 4,963 25,245 (9,870) (12,353) (1,137,583) (1,045,457) 88,908 65,248 Net cash used in operating activities 30 (1,048,675) (980,209) Cash flows from investing activities Payments for computer equipment Payments for intangibles Payments for exploration and evaluation Proceeds from short term investments Proceeds from farm-out arrangement Net cash from/(used in) investing activities Cash flows from financing activities Payment of principal element of lease liabilities Net cash used in financing activities Net increase/(decrease) in cash and cash equivalents Cash and cash equivalents at the beginning of the financial year 11 13 14 (6,862) (30,001) - - (851,721) (726,453) - - 906,423 5,000,000 (888,584) 5,179,970 (91,130) (57,028) (91,130) (57,028) (2,028,389) 4,142,733 5,077,191 934,458 Cash and cash equivalents at the end of the financial year 8 3,048,802 5,077,191 The above consolidated statement of profit or loss and other comprehensive income should be read in conjunction with the accompanying notes 34 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 30 June 2021 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 23 September 2021. 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 following Accounting Standards and Interpretations are most relevant to the Consolidated Entity: 21RU-005 Cloud computing arrangement costs The IFRS® Interpretations Committee (IFRIC) has issued two final agenda decisions on cloud computing arrangements. The March 2019 decision considers whether a customer receives a software asset at the contract commencement date or a service over the contract term. The April 2021 decision builds on the 2019 decision and considers how a customer accounts for configuration or customisation costs where an intangible asset is not recognised. These decisions have no impact on the Consolidated Entity's financial statements. 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 2021 of the Consolidated Entity results in an excess of current assets over current liabilities of $2,067,184 (30 June 2020: $4,033,946). The Consolidated Entity made a loss after tax of $1,142,095 during the financial year (2020 loss: $3,006,065) and had net operating cash outflows of $1,048,675 (2020: $980,209). The cash balances, including term deposits, as at 30 June 2021 was $3,142,379 (2020: $5,170,768). 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 Consolidated Entity's funding requirements as and when they fall due the Consolidated Entity 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 Consolidated Entity’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 Consolidated Entity. In July and August 2021, the Australian economy has experienced disruption related to COVID-19 triggered Statewide lockdowns across all major States including New South Wales, Victoria and Queensland. These lockdowns have caused disruption to the broader business community and the Australian mining and exploration industry's operations have not been immune. There is significant uncertainty around the breadth and duration of business disruptions related to COVID-19 and therefore the Consolidated Entity has taken precautionary measures by temporarily closing the Consolidated Entity’s office and having arranged for the employees to work remotely, as well as curtailing travel. Management believes that this will allow the continuance of its current principal business activities. At the date of this report, the impact of these measures is not expected to significantly impact the completion of the activities currently being undertaken. However, as the circumstances continue to evolve, there may be disruptions to future activities, 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. Based on the aforementioned conclusions reached by the Directors, the financial statements have been prepared 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'). 35 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 26. 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 2021 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 36 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: (a) the rights to tenure of the area of interest are current; and (b) at least one of the following conditions is also met: (i) 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; or (ii) 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. 37 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. 38 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 2021. 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. Share-based payment transactions The Consolidated Entity measures the cost of equity-settled transactions with employees by reference to the fair value of the equity instruments at the date at which they are granted. The fair value is determined by using the Hoadley Trading & Investment Tools (“Hoadley”) ESO5 option valuation model taking into account the terms and conditions upon which the instruments were granted. The accounting estimates and assumptions relating to equity-settled share-based payments would have no impact on the carrying amounts of assets and liabilities within the next annual reporting period but may impact profit or loss and equity. 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. Impairment of non-financial assets other than goodwill and other indefinite life intangible assets The Consolidated Entity assesses impairment of non-financial assets other than goodwill and other indefinite life intangible assets at each reporting date by evaluating conditions specific to the Consolidated Entity and to the particular asset that may lead to impairment. If an impairment trigger exists, the recoverable amount of the asset is determined. This involves fair value less costs of disposal or value-in-use calculations, which incorporate a number of key estimates and assumptions. 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. Significant judgement is required by management when assessing each of area of interest and therefore management's judgement carries the risk of been misstated. 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. 39 NOTE 5. OTHER INCOME COVID-19 incentives 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. NOTE 6. EXPENSES Loss before income tax includes the following specific expenses: Depreciation Plant and equipment Right-of-use assets Total depreciation Amortisation Software Total depreciation and amortisation Post-employment benefit plans – Superannuation contributions Employment entitlements Consolidated 2021 $ 2020 $ 82,908 75,873 Consolidated 2021 $ 2020 $ (4,368) (3,769) (86,340) (86,346) (90,708) (90,115) (27,428) (20,092) (118,136) (110,207) (26,306) (29,106) (541,909) (442,694) (568,215) (471,800) Finance costs Interest and finance charges paid/payable on lease liabilities (9,870) (15,773) 40 NOTE 7. INCOME TAX EXPENSE Numerical reconciliation of income tax expense and tax at the statutory rate Loss before income tax expense Tax at the statutory tax rate of 26% (2020: 27.5%) Tax effect amounts which are not deductible/(taxable) in calculating taxable income: Entertainment expenses Impairment of exploration assets Share-based payments Prior year under/over adjustment Amounts not brought to account as deferred tax assets Non-assessable non-exempt income – cashflow boost Proceeds from farm-out arrangement tax at statutory tax rates Previously unrecognised DTA now brought to account Income tax expense 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 un- deducted expenditure is eligible for annual compounding at set rates. The compound amount can be deducted against assessable receipts in future years. Deferred tax assets not recognised Deferred tax assets not recognised comprises temporary differences attributable to: Tax losses Total deferred tax assets not recognised The above potential tax benefit, which includes 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: (i) 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; (ii) the Consolidated Entity continues to comply with the conditions for deductibility imposed by law; and (iii) no change in tax legislation adversely affects the Company in realising the benefits from deducting the losses. Consolidated 2021 $ 2020 $ (1,142,095) (3,006,065) (296,945) (826,668) 949 - 2,359 2,986 1,037 518,744 - - 290,651 293,137 - - - - - 13,750 - 1,375,000 (1,375,000) - The Company has not recognised a deferred tax asset with respect to the carried forward un-deducted expenditure. Consolidated 2021 $ 2020 $ 15,247,233 15,887,558 15,247,233 15,887,558 41 NOTE 8. CURRENT ASSETS – CASH AND CASH EQUIVALENTS Cash at bank 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. Consolidated 2021 $ 2020 $ 3,048,802 5,077,191 NOTE 9. CURRENT ASSETS – OTHER RECEIVABLES Consolidated 2020 $ 6,000 865 1,351 2021 $ 23,659 472 7,621 31,752 8,216 Other receivables Interest receivable GST receivable Other receivables represent reimbursement of venture costs by joint venture partners. 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. NOTE 10. CURRENT ASSETS – SHORT TERM INVESTMENTS Cash on deposit This amount relates to cash on deposit held with a term to maturity greater than 3 months. Consolidated 2021 $ 2020 $ 93,577 93,577 42 NOTE 11. NON-CURRENT ASSETS – PROPERTY, PLANT AND EQUIPMENT Furniture and equipment – at cost Less: Accumulated depreciation Computer equipment – at cost Less: Accumulated depreciation Reconciliations Reconciliations of the written down values at the beginning and end of the current and previous financial year are set out below: Consolidated Balance at 1 July 2019 Depreciation expense Balance at 30 June 2020 Additions Depreciation expense Balance at 30 June 2021 Consolidated 2021 $ 2020 $ 184,083 184,083 (184,083) (184,083) - - 25,708 (9,183) 16,525 18,845 (4,814) 14,031 16,525 14,031 Computer equipment $ 17,800 (3,769) 14,031 6,862 (4,368) Total $ 17,800 (3,769) 14,031 6,862 (4,368) 16,525 16,525 Accounting policy for furniture, computer and 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: Computer and equipment 3-7 years The residual values, useful lives and depreciation methods are reviewed, and adjusted if appropriate, at each reporting date. 43 NOTE 12. NON-CURRENT ASSETS – RIGHT-OF-USE ASSETS 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 the security interests in the leased assets that are held by the lessor. Leased assets may not be used as security for borrowing purposes. Consolidated 2021 $ 2020 $ 251,842 251,842 (172,686) (86,346) 79,156 165,496 $ 251,842 (86,346) 165,496 (86,340) Total $ 251,842 (86,346) 165,496 (86,340) 79,156 79,156 Reconciliations Reconciliations of the written down values at the beginning and end of the current and previous financial year are set out below: Office space- right-of-use Less: Accumulated depreciation Refer note 20 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 2021. Consolidated Balance at 1 July 2019 Depreciation expense Balance at 30 June 2020 Depreciation expense Balance at 30 June 2021 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. 44 NOTE 13. NON-CURRENT ASSETS – INTANGIBLES Software – at cost Less: Accumulated amortisation Reconciliations Reconciliations of the written down values at the beginning and end of the current and previous financial year are set out below: Consolidated Balance at 1 July 2019 Amortisation expense Balance at 30 June 2020 Additions Amortisation expense Balance at 30 June 2021 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. NOTE 14. NON-CURRENT ASSETS – EXPLORATION AND EVALUATION Exploration and evaluation expenditure Less: Impairment Consolidated 2021 $ 2020 $ 364,791 334,790 (288,150) (260,722) 76,641 74,068 Software $ Total $ 94,160 94,160 (20,092) (20,092) 74,068 30,001 74,068 30,001 (27,428) (27,428) 76,641 76,641 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. Consolidated 2021 $ 2020 $ 5,374,599 6,432,880 - (1,886,343) 5,374,599 4,546,537 45 Reconciliations Reconciliations of the written down values at the beginning and end of the current and previous financial year are set out below: Consolidated Balance at 1 July 2019 Expenditure during the year Area of interest VIC / P57 Area of interest T49P Area of interest VIC/P74 Area of interest WA-527-P $ $ 1,870,088 8,440,582 $ - Total $ $ 425,217 10,735,887 16,255 152,245 185,709 342,784 696,993 Impairment of exploration assets (1,886,343) - (5,000,000) - - - - (1,886,343) (5,000,000) 3,592,827 424,751 185,709 339,241 768,001 4,546,537 64,070 828,062 4,017,578 524,950 832,071 5,374,599 - - - - 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. Exploration and evaluation costs expensed Upon completion of the to the aforementioned impairment review, it was concluded that area of interest VIC/P57 currently will not generate future economic benefits as a result of which exploration costs of $33,088 incurred were immediately expensed in the statement of profit or loss and other comprehensive income in the year ended 30 June 2021. Proceeds from farm-out arrangement Balance at 30 June 2020 Additions Balance at 30 June 2021 The exploration and evaluation assets relate to VIC/P74, an offshore project in the Gippsland Basin in Victoria, T/49P which is an offshore project in the Otway Basin in Tasmania and WA-527-P in Western Australia. The recoverability of the exploration and evaluation expenditure's carrying amounts is dependent on the successful development and commercial exploitation, or alternatively the farm-out or sale, of the respective areas of interest. Area of interest VIC/P57 is an offshore project in the Gippsland Basin in Victoria which was written down to a carrying amount of nil as of 30 June 2020. The Consolidated Entity has carried out an impairment review of the carrying amount of its exploration expenditure in relation to VIC/P74, T/49P and WA-527-P following the end of the financial year as at 30 June 2021. Based on the review no impairments were identified in relation to these tenements. 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. Please refer to note 28 for further information on the Consolidated Entity’s farm-out arrangements. 46 NOTE 15. CURRENT LIABILITIES – TRADE AND OTHER PAYABLES Trade payables Research and development tax grant Sundry payables and accrued expenses The Research and development tax grant relates to an R&D tax incentive refund received during the financial year ended 30 June 2012. The Company had received a notification that AusIndustry had reversed this claim, and hence this amount is carried as a liability. Refer to note 21 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. Consolidated 2020 $ 150,649 695,894 87,634 2021 $ 54,467 695,894 69,984 820,345 934,177 NOTE 16. CURRENT LIABILITIES – EMPLOYEE BENEFITS Annual leave Long service leave Employee benefits Accounting policy for employee benefits Short-term employee benefits Liabilities for wages and salaries, including non-monetary benefits, annual leave and long service leave expected to be settled wholly within 12 months of the reporting date are measured at the amounts expected to be paid when the liabilities are settled. Consolidated 2021 $ 2020 $ 58,076 22,145 136,956 126,124 36,880 - 231,912 148,269 47 NOTE 17. NON-CURRENT LIABILITIES – EMPLOYEE BENEFITS Long service leave Consolidated 2021 $ 2020 $ 4,585 5,830 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. NOTE 18. EQUITY – ISSUED CAPITAL 2021 Shares 2020 Shares Consolidated 2021 $ 2020 $ Ordinary shares – fully paid 265,188,372 265,188,372 55,483,678 55,483,678 NOTE 19. 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. 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 2020 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. 48 NOTE 20. LEASE LIABILITIES Lease liabilities Current Non-current Right of use lease assets note 12 Lease liability maturity analysis – contractual undiscounted cash flows Less than one year Two to five years Total undiscounted lease liabilities Lease liability finance costs During the year ended 30 June 2021, the Consolidated Entity incurred interest charges of $9,870, as disclosed in note 6. Lease liability outflows Lease liability related cash outflows are disclosed in the statement of cashflows. Consolidated 2021 $ 2020 $ 96,614 102,039 - 85,705 96,614 187,744 Consolidated 2021 $ 2020 $ 79,156 165,496 Consolidated 2021 2020 96,614 112,246 - 91,711 96,614 203,957 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 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. 49 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. NOTE 21. FINANCIAL INSTRUMENTS 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. The transactions and balances denominated in US dollars are not material to these financial statements. 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 2021 was $0.6878 (30 June 2020: $0.6878). 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. 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. 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. 50 Consolidated – 2021 Non-derivatives Non-interest bearing Trade and other payables Interest-bearing – variable Lease liability Total non-derivatives Consolidated – 2020 Non-derivatives Non-interest bearing Trade and other payables Interest-bearing – variable Lease liability Between 1 and 2 years Between 2 and 5 years Over 5 years Weighted average interest rate % - 1 year or less $ 820,345 7.50% 96,614 916,959 - 934,177 $ - - - - Remaining contractual maturities $ 820,345 96,614 916,959 934,177 203,957 1,138,134 $ - - - - - - $ - - - - - - Total non-derivatives 1,046,423 91,711 7.50% 112,246 91,711 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. NOTE 22. KEY MANAGEMENT PERSONNEL DISCLOSURES Directors The following persons were Directors of 3D Oil Limited during the financial year: Mr Noel Newell Mr Ian Tchacos Mr Leo De Maria Executive Chairman Non-Executive Director Non-Executive Director Compensation The aggregate compensation made to Directors and other members of key management personnel of the Consolidated Entity is set out below: Short-term employee benefits Post-employment benefits Long-term benefits Consolidated 2021 $ 2020 $ 485,041 437,427 29,697 9,946 31,278 14,414 524,684 483,119 51 NOTE 23. REMUNERATION OF AUDITORS During the financial year the following fees were paid or payable for services provided by Grant Thornton Audit Pty Ltd, the auditor of the Company: Audit services – Grant Thornton Audit Pty Ltd Consolidated 2021 $ 2020 $ Audit or review of the financial statements 55,000 53,500 NOTE 24. COMMITMENTS Exploration Licenses – Commitments for Expenditure Committed at the reporting date but not recognised as liabilities, payable: Within one year One to five years 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 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. On 8 October 2020, NOPTA approved Hibiscus Petroleum Berhad to enter into a Joint Venture with the Company in the offshore Gippsland Basin exploration permit VIC/P74, in which the Company remains the operator with 50% equity. The Company has included in in the above commitments its share of indicative expenditure relating to VIC/P74 up to 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 4 in relation to VIC/P74, the current indicative expenditure commitment for Years 4-6 is currently gross $42.1 million, and this would be occurring in 2022-2025 years. In relation to VIC/P57, the joint venture applied to NOPTA in September 2017 for a further 5 year tenure, which was granted on 7 March 2018. 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. During the year ended 30 June 2021, the Joint Venture received approval for a 12 Month Suspension and Extension to the Primary Term of VIC/P57, which will now expire on 6 March 2022. If the Company was to proceed beyond year 3 in relation to VIC/P57, the current indicative expenditure commitment for Years 4-5 is currently gross $31.3 million and this would be occurring in 2022-2023 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 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 4 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 2022-2023 years. Consolidated 2021 $ 2020 $ 3,060,000 544,133 - 1,066,667 3,060,000 1,610,800 The commitments above does not include commitments for indicative expenditure relating to Exploration Permit T49P, as they are expected to be covered by the farm-in partner, ConocoPhillips Australia Pty Ltd (COP), 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. During the March 2021 quarter, the joint venture was awarded a 30-month Suspension and Extension on the Year 5 permit commitments, allowing up until 21 August 2023 to complete the Year 5 work programme. Upon interpretation of the 3D seismic survey, COP may elect to drill an exploration well which will fulfill the current Year 6 work programme. 52 NOTE 25. RELATED PARTY TRANSACTIONS Parent entity 3D Oil Limited is the parent entity. Subsidiaries Interests in subsidiaries are set out in note 27. Joint operations Interests in joint operations are set out in note 28. Key management personnel Disclosures relating to key management personnel are set out in note 22 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. NOTE 26. PARENT ENTITY INFORMATION Set out below is the supplementary information about the parent entity. Statement of profit or loss and other comprehensive income Loss after income tax Total comprehensive income Statement of financial position Total current assets Total assets Total current liabilities Total liabilities Equity Issued capital Share-based payments reserve Accumulated losses Total equity 2021 $ Parent 2020 $ (1,142,047) (3,003,234) (1,142,047) (3,003,234) 2021 $ Parent 2020 $ 3,123,331 5,125,658 5,976,850 7,267,372 1,113,888 1,184,485 1,118,473 1,276,020 55,483,678 55,483,678 9,072 - (50,634,373) (49,492,326) 4,858,377 5,991,352 53 — 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. 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 2021 and 30 June 2020. Contingent liabilities The parent entity had no contingent liabilities as at 30 June 2021 and 30 June 2020. Capital commitments – Property, plant and equipment The parent entity had no capital commitments for property, plant and equipment as at 30 June 2021 and 30 June 2020. 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. NOTE 27. INTERESTS IN SUBSIDIARIES The consolidated financial statements incorporate the assets, liabilities and results of the following subsidiary in accordance with the accounting policy described in note 2: Name 3D Oil T49P Pty Ltd Principal place of business / Country of incorporation Australia NOTE 28. INTERESTS IN JOINT OPERATIONS 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. Information relating to joint operations that are material to the Consolidated Entity are set out below: Name Principal place of business / Country of incorporation T/49P, Otway Basin, offshore Tasmania Australia VIC/P74, Gippsland Basin, offshore Victoria* Australia VIC/P57, Gippsland Basin, offshore Victoria Australia Ownership interest 2021 % 2020 % 100.00% 100.00% Ownership interest 2021 % 20.00% 50.00% 24.90% 2020 % 20.00% 100.00% 24.90% *On 9 October 2020, the Consolidated Entity announced that the NOPTA approved Hibiscus Petroleum Berhad to enter a Joint Venture with TDO in the offshore Gippsland Basin exploration permit VIC/P74. Under the terms of the Assignment Agreement, TDO will remain as operator with 50% equity. 54 NOTE 29. EVENTS AFTER THE REPORTING PERIOD In accordance with the announcement of 1 March 20121, the Consolidated Entity announced on 11 August 2021 that ConocoPhillips Australia SH1 Pty Ltd (“ConocoPhillips Australia”) as operator of the T/49P joint venture with TDO’s wholly owned subsidiary, 3D Oil T49P Pty Ltd, will commence acquisition of the Sequoia MSS 3D seismic survey using the Shearwater vessel the Geo Coral. The survey is planned to cover an area of approximately 2,500 km2 with the seismic survey acquisition estimated to take approximately 60 days between the middle of August and the end of October 2021. ConocoPhillips Australia is the operator of the T/49P joint venture with an 80% interest in the T/49P Permit, the Company having the remaining 20% interest. Under the terms of the Farmout Agreement, ConocoPhillips Australia was to acquire a minimum of 1580 km2 of 3D seismic at no expense to the Company (TDO ASX Announcement 11 June 2020). The proposed increase in size of the acquisition area will provide coverage of all leads within the T/49P Permit and tie in with the previously acquired Flanagan 3D seismic survey. No other matter or circumstance has arisen since 30 June 2021 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. NOTE 30. RECONCILIATION OF LOSS AFTER INCOME TAX TO NET CASH USED IN OPERATING ACTIVITIES Loss after income tax expense for the year Adjustments for: Depreciation and amortisation Share-based payments Impairment of exploration and evaluation Forgiveness of lease payments Accrued interest Change in operating assets and liabilities: Decrease in other receivables Increase in prepayments Decrease in trade and other payables Increase in employee benefits Net cash used in operating activities NOTE 31. LOSS PER SHARE Consolidated 2021 $ 2020 $ (1,142,095) (3,006,065) 118,136 110,207 9,072 - - - - 1,886,343 (4,625) 3,420 123 (2,477) (113,832) 82,398 22,118 (1,046) (8,737) 18,176 (1,048,675) (980,209) Consolidated 2021 $ 2020 $ Loss after income tax attributable to the owners of 3D Oil Limited (1,142,095) (3,006,065) Weighted average number of ordinary shares used in calculating basic loss per share Number Number 265,188,372 265,188,372 Weighted average number of ordinary shares used in calculating diluted loss per share 265,188,372 265,188,372 Basic earnings per share Diluted earnings per share Cents (0.43) (0.43) Cents (1.13) (1.13) 55 Accounting policy for earnings loss per share Basic loss per share Basic loss 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 loss per share Diluted loss per share adjusts the figures used in the determination of basic loss 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. NOTE 32. SHARE-BASED PAYMENTS On 17 November 2020, the Company issued 225,806 performance rights to Directors and on 15 February 2021, 516,128 performance rights to employees. The performance rights issued to the Company's Directors have an exercise price of nil, a share price hurdle of $0.09 (9 cents), vesting date of 17 November 2022 and expire on 17 November 2023. The performance rights issued to the Company's employees in February 2021 have an exercise price of nil, a share price hurdle of $0.09 (9 cents), a vesting date of 17 November 2022 and expire 3 years following the grant date. Exercise price $0.000 $0.000 $0.000 $0.000 $0.000 Balance at the start of the year Granted Exercised Expired/ forfeited/ other Balance at the end of the year - - - - - - 225,806 80,645 80,645 112,903 241,935 741,934 - - - - - - - - - - - - 225,806 80,645 80,645 112,903 241,935 741,934 Share price at grant date Exercise price Expected volatility Dividend yield Risk-free interest rate Fair value at grant date $0.056 $0.057 $0.055 $0.055 $0.054 $0.000 $0.000 $0.000 $0.000 $0.000 80.000% 80.000% 80.000% 80.000% 80.000% - - - - - 0.110% 0.105% 0.105% 0.105% 0.105% $0.045 $0.054 $0.054 $0.054 $0.054 2021 Grant date Expiry date 17/11/2020 17/11/2023 28/01/2021 28/01/2024 29/01/2021 29/01/2024 01/02/2021 01/02/2024 11/02/2021 11/02/2024 For the performance rights issued during the current financial year, the valuation model inputs used to determine the fair value at the grant date, are as follows: Grant date Expiry date 17/11/2020 17/11/2023 28/01/2021 28/01/2024 29/01/2021 29/01/2024 01/02/2021 01/02/2024 11/02/2021 11/02/2024 The weighted average remaining contractual life of performance rights at 30 June 2021 is 2.53 years. 56 An additional expense is recognised, over the remaining vesting period, for any modification that increases the total fair value of the share-based compensation benefit as at the date of modification. If the non-vesting condition is within the control of the Consolidated Entity or employee, the failure to satisfy the condition is treated as a cancellation. If the condition is not within the control of the Consolidated Entity or employee and is not satisfied during the vesting period, any remaining expense for the award is recognised over the remaining vesting period, unless the award is forfeited. If equity-settled awards are cancelled, it is treated as if it has vested on the date of cancellation, and any remaining expense is recognised immediately. If a new replacement award is substituted for the cancelled award, the cancelled and new award is treated as if they were a modification. Accounting policy for share-based payments Equity-settled and cash-settled share- based compensation benefits are provided to employees. Equity-settled transactions are awards of shares, or options over shares, that are provided to employees in exchange for the rendering of services. Cash-settled transactions are awards of cash for the exchange of services, where the amount of cash is determined by reference to the share price. The cost of equity-settled transactions are measured at fair value on grant date. Fair value is independently determined using the Hoadley Trading & Investment Tools (“Hoadley”) ESO5 option valuation model. The option pricing model that takes into account the exercise price, the share hurdle price, the impact of dilution, the share price at grant date and expected price volatility of the underlying share, the expected dividend yield and the risk free interest rate for the term of the option, together with non-vesting conditions that do not determine whether the Consolidated Entity receives the services that entitle the employees to receive payment. The cost of equity-settled transactions are recognised as an expense with a corresponding increase in equity over the vesting period. The cumulative charge to profit or loss is calculated based on the grant date fair value of the award, the best estimate of the number of awards that are likely to vest and the expired portion of the vesting period. The amount recognised in profit or loss for the period is the cumulative amount calculated at each reporting date less amounts already recognised in previous periods. Market conditions are taken into consideration in determining fair value. Therefore, any awards subject to market conditions are considered to vest irrespective of whether or not that market condition has been met, provided all other conditions are satisfied. If equity-settled awards are modified, as a minimum an expense is recognised as if the modification has not been made. DIRECTORS' DECLARATION In the Directors' opinion: — the attached financial statements and notes comply with the Corporations Act 2001, the Accounting Standards, the Corporations Regulations 2001 and other mandatory professional reporting requirements; — the attached financial statements and notes comply with International Financial Reporting Standards as issued by the International Accounting Standards Board as described in note 2 to the financial statements; — the attached financial statements and notes give a true and fair view of the Consolidated Entity's financial position as at 30 June 2021 and of its performance for the financial year ended on that date; and — there are reasonable grounds to believe that the Company will be able to pay its debts as and when they become due and payable. The Directors have been given the declarations required by section 295A of the Corporations Act 2001. Signed in accordance with a resolution of Directors made pursuant to section 295(5) (a) of the Corporations Act 2001. On behalf of the Directors Noel Newell Executive Chairman 23 September 2021 Melbourne 57 [This page has intentionally been left blank for the insertion of page one of the independent auditor's report] 58 Grant Thornton Audit Pty Ltd ACN 130 913 594 a subsidiary or related entity of Grant Thornton Australia Ltd ABN 41 127 556 389 ‘Grant Thornton’ refers to the brand under which the Grant Thornton member firms provide assurance, tax and advisory services to their clients and/or refers to one or more member firms, as the context requires. Grant Thornton Australia Ltd is a member firm of Grant Thornton International Ltd (GTIL). GTIL and the member firms are not a worldwide partnership. GTIL and each member firm is a separate legal entity. Services are delivered by the member firms. GTIL does not provide services to clients. GTIL and its member firms are not agents of, and do not obligate one another and are not liable for one another’s acts or omissions. In the Australian context only, the use of the term ‘Grant Thornton’ may refer to Grant Thornton Australia Limited ABN 41 127 556 389 and its Australian subsidiaries and related entities. GTIL is not an Australian related entity to Grant Thornton Australia Limited. Liability limited by a scheme approved under Professional Standards Legislation. www.grantthornton.com.au Collins Square, Tower 5 727 Collins Street Docklands Victoria 3008 Correspondence to: GPO Box 4736 Melbourne Victoria 3001 T 61 3 8320 2222 F 61 3 8320 2200 E info.vic@au.gt.com W www.grantthornton.com.au Independent Auditor’s Report To the Members of 3D Oil Limited Report on the audit of the financial report Opinion We have audited the financial report of 3D Oil Limited (the Company) and its controlled entities (the Consolidated Entity), which comprises the consolidated statement of financial position as at 30 June 2021, the consolidated statement of profit or loss and other comprehensive income, consolidated statement of changes in equity and consolidated statement of cash flows for the year then ended, and notes to the financial statements, including a summary of significant accounting policies, and the Directors’ declaration. In our opinion, the accompanying financial report of 3D Oil Ltd and controlled entities is in accordance with the Corporations Act 2001, including: a giving a true and fair view of the Consolidated Entity’s financial position as at 30 June 2021 and of its performance for the year ended on that date; and b complying with Australian Accounting Standards and the Corporations Regulations 2001. Basis for opinion We conducted our audit in accordance with Australian Auditing Standards. Our responsibilities under those standards are further described in the Auditor’s Responsibilities for the Audit of the Financial Report section of our report. We are independent of the Consolidated Entity in accordance with the auditor independence requirements of the Corporations Act 2001 and the ethical requirements of the Accounting Professional and Ethical Standards Board’s APES 110 Code of Ethics for Professional Accountants (the Code) that are relevant to our audit of the financial report in Australia. We have also fulfilled our other ethical responsibilities in accordance with the Code. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion. [This page has intentionally been left blank for the insertion of page two of the independent auditor's report] 59 2 Key audit matters Key audit matters are those matters that, in our professional judgement, were of most significance in our audit of the financial report of the current period. These matters were addressed in the context of our audit of the financial report as a whole, and in forming our opinion thereon, and we do not provide a separate opinion on these matters. Key audit matter How our audit addressed the key audit matter Exploration and Evaluation Assets – valuation (Note 14) As all of the tenements held by 3D Oil Limited and its controlled entities (the Consolidated Entity) 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 Consolidated Entity 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; • Assessing management's treatment of the Joint Operating Agreement entered into during the period; • Evaluating management's assessment of impairment indicators for the Consolidated Entity's capitalised exploration assets under AASB 6 by: o 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; o 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; o Obtaining an understanding as to whether any data exists that indicates the carrying value of these exploration and evaluation assets are unlikely to be recovered from successful development or by sale; o Considering any other available evidence of impairment. • Assessing management’s consequent determination of impairment loss; and • Evaluating related financial statement disclosures. This page has intentionally been left blank for the insertion of page three of the independent auditor's report] 60 3 Key audit matter How our audit addressed the key audit matter Going concern (Note 2) 3D Oil Limited and its controlled entities (the Consolidated Entity) made a loss after tax of $1.1m for the year ended 30 Jun 2021. The working capital position of the Consolidated Entity was $2.0m at 30 June 2021 as an excess of current assets over current liabilities. The cash and cash equivalents reduced from $5.2m at 30 June 2020 to $3.1m at 30 June 2021 as a result of $1.2m of operating expenses and $0.8m of capitalised exploration and evaluation expenditures. The Consolidated Entity 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 Consolidated Entity’s tenements, progress project feasibility studies, and to cover corporate overheads. Under AASB 101: Presentation of Financial Statements the Directors of the Consolidated Entity are required to assess the appropriateness of the preparation of the financial report on a going concern basis. The Consolidated Entity has prepared cash flow projections which include a number of assumptions and judgements, including estimates of project and administrative expenditure. These projections are used to support the sufficiency of working capital. This area is a key audit matter due to its importance to the financial report and the level of judgement involved. Our procedures included, amongst others: • Assessing the going concern assumptions for reasonableness by discussing with management and reviewing board minutes; • Obtaining and evaluating a copy of management’s cash-flow forecast for mathematical accuracy and assessing whether it appears the current cash levels can sustain the operations of the Consolidated Entity for the 12 month period from date of signing of the financial statements; • Assessing 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 • Evaluating related financial statement disclosures. Information other than the financial report and auditor’s report thereon The Directors are responsible for the other information. The other information comprises the information included in the Consolidated Entity’s annual report for the year ended 30 June 2021, but does not include the financial report and our auditor’s report thereon. Our opinion on the financial report does not cover the other information and we do not express any form of assurance conclusion thereon. In connection with our audit of the financial report, our responsibility is to read the other information and, in doing so, consider whether the other information is materially inconsistent with the financial report or our knowledge obtained in the audit or otherwise appears to be materially misstated. If, based on the work we have performed, we conclude that there is a material misstatement of this other information, we are required to report that fact. We have nothing to report in this regard. 61 4 Responsibilities of the Directors’ for the financial report The Directors of the Company are responsible for the preparation of the financial report that gives a true and fair view in accordance with Australian Accounting Standards and the Corporations Act 2001 and for such internal control as the Directors determine is necessary to enable the preparation of the financial report that gives a true and fair view and is free from material misstatement, whether due to fraud or error. In preparing the financial report, the Directors are responsible for assessing the Consolidated Entity’s ability to continue as a going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless the Directors either intend to liquidate the Company or to cease operations, or have no realistic alternative but to do so. Auditor’s responsibilities for the audit of the financial report Our objectives are to obtain reasonable assurance about whether the financial report as a whole is free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with the Australian Auditing Standards will always detect a material misstatement when it exists. Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions of users taken on the basis of this financial report. A further description of our responsibilities for the audit of the financial report is located at the Auditing and Assurance Standards Board website. https://www.auasb.gov.au/auditors_responsibilites/ar1_2020.pdf. This description forms part of our auditor’s report. Report on the remuneration report Opinion on the remuneration report We have audited the Remuneration Report, included in pages 24 to 27, of the Directors’ report for the year ended 30 June 2021. In our opinion, the Remuneration Report of 3D Oil Limited, for the year ended 30 June 2021 complies with section 300A of the Corporations Act 2001. Responsibilities The Directors of the Company are responsible for the preparation and presentation of the Remuneration Report in accordance with section 300A of the Corporations Act 2001. Our responsibility is to express an opinion on the Remuneration Report, based on our audit conducted in accordance with Australian Auditing Standards. Grant Thornton Audit Pty Ltd Chartered Accountants D G Ng Partner – Audit & Assurance Melbourne, 23 September 2021 SHAREHOLDER INFORMATION The shareholder information set out below was applicable as at 10 September 2021. Distribution of equitable securities Analysis of number of equitable security holders by size of holding: Number Number of holders of ordinary shares of ordinary shares units % of ordinary shares of holders of performance rights of performance rights % of performance rights 1 to 1,000 1,001 to 5,000 5,001 to 10,000 10,001 to 100,000 100,001 and over 49 121 128 457 275 15,444 399,282 1,102,823 19,138,031 0.01 0.15 0.42 7.22 244,532,792 92.20 1,030 265,188,372 100.00 Holding less than a marketable parcel 240 937,549 0.35 - - - 4 3 7 - - - - 274,193 467,741 - - - 36.96 63.04 741,934 100.00 - - 62 Equity security holders Twenty largest quoted equity security holders The names of the twenty largest security holders of quoted equity securities are listed below: MR NOEL NEWELL OCEANIA HIBISCUS SDN BHD\C BILL HOPPER SANLIRRA PTY LTD CITICORP NOMINEES PTY LIMITED BLAMNCO TRADING PTY LTD BNP PARIBAS NOMINEES PTY LTD SIX SIS LTD NORTHERN BUSINESS PLANNING CENTRE PTY LTD HSBC CUSTODY NOMINEES (AUSTRALIA) LIMITED – A/C 2 PENGOLD PTY LTD MR TAI TRAN VIN NAIDU + WENDY NAIDU HSBC CUSTODY NOMINEES (AUSTRALIA) LIMITED MR JOHN PHILIP DANIELS MR GIOVANNI MONTELEONE + MRS FRANCES MONTELEONE MR RUSSELL BARWICK EILIE SUNSHINE PTY LTD SANLIRRA PTY LTD MICLON PTY LTD MR VINCENZO MONTELEONE Unquoted equity securities Performance rights over ordinary shares issued Substantial holders Substantial holders in the Company are set out below: NOEL NEWELL OCEANIA HIBISCUS SDN BHD\C Ordinary shares % of total shares issued 14.56 11.68 2.44 2.11 2.07 1.89 1.79 1.69 1.63 1.40 1.24 1.07 1.01 0.99 0.96 0.94 0.94 0.87 0.81 0.75 Number held 38,604,620 30,963,000 6,475,000 5,600,000 5,500,348 5,000,000 4,755,500 4,485,616 4,322,740 3,714,000 3,300,000 2,837,500 2,670,863 2,626,150 2,550,000 2,500,000 2,500,000 2,300,000 2,146,348 2,000,000 134,851,685 50.84 Number on issue 741,934 Number of holders 7 Ordinary shares % of total shares issued 16.66 11.68 Number held 44,192,229 30,963,000 63 Voting rights The voting rights attached to ordinary shares are set out below: Ordinary shares All issued shares carrying voting rights on a one-for-one basis. Performance rights There are no voting rights attached to performance rights There are no other classes of equity securities. Corporate Governance Statement The Company’s 2021 Corporate Governance Statement is available on the Company’s website at: https://www.3doil.com.au/ about/corporate-governance Annual General Meeting 3D Oil Limited advises that its Annual General Meeting will be held on Monday, 15 November 2021. The time and other details relating to the meeting will be advised in the Notice of Meeting to be sent to all shareholders and released to ASX in due course. In accordance with the ASX Listing Rules and the Company’s Constitution, the closing date for receipt of nominations for the position of Director are required to be lodged at the registered office of the Company by 5.00pm (AEST) on 4 October 2021. CORPORATE DIRECTORY Auditor Grant Thornton Audit Pty Ltd Collins Square Tower 5 727 Collins Street Melbourne, Victoria 3008 Solicitors Baker McKenzie Level 19, 181 William Street Melbourne, Victoria 3000 Stock exchange listing 3D Oil Limited securities are listed on the Australian Securities Exchange (ASX Code: TDO) Website 3doil.com.au Directors Noel Newell (Executive Chairman) Ian Tchacos (Non-Executive Director) Leo De Maria (Non-Executive Director) Company secretaries Melanie Leydin Stefan Ross Registered office Level 18, 41 Exhibition Street Melbourne, VIC 3000 Telephone: (03) 9650 9866 Principal place of business Level 18, 41 Exhibition Street Melbourne, VIC 3000 Telephone: (03) 9650 9866 Share register Computershare Investor Services Pty Limited 452 Johnston Street Abbotsford, Victoria 3067 Telephone: (03) 9415 5000 64

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