More annual reports from 3D Oil Limited:
2023 ReportANNUAL REPORT 2022 THE SEQUOIA 3D MARINE SEISMIC SURVEY WILL ALLOW THE JOINT VENTURE TO EVALUATE THE FULL POTENTIAL OF T/49P WITH HIGH-QUALITY, MODERN 3D SEISMIC Executive Chairman’s Letter to shareholders Review of operations Directors' report 2 4 21 Auditor's independence declaration 32 Consolidated statement of profit or loss and other comprehensive income Consolidated statement of financial position Consolidated statement of changes in equity 34 35 36 Consolidated statement of cash flows 37 Notes to the consolidated financial statements Directors' declaration Independent auditor's report to the members of 3D Oil Limited Shareholder information Corporate directory Front cover image courtesy of Shearwater 38 60 61 64 66 1 EXECUTIVE CHAIRMAN’S LETTER TO SHAREHOLDERS Dear fellow Shareholders In last years chairman's letter I state that “3D Oil is now fully committed to becoming a significant east coast gas producer…”. I am pleased to report the Company has again progressed towards reaching that objective. The high points for the Company during the year included; — Acquired a new and highly prospective exploration license in the Otway Basin VIC/P79. — Entered into a farmout agreement with ConocoPhilips Australia for VIC/P79. — Completed, along with its Joint Venture partner (ConocoPhilips Australia) an extensive seismic program over the T/49P exploration license. — Continue farmout discussions on WA-527-P. — Acquired a prospective gas storage license (GSEL 759) with the Company working on energy transitional strategies for the new and emerging energy demands. — Secure approximately A$4.6 million in cash as a result of farmout activities during the year thereby reducing the need raise funds from shareholder. — At the time of this report the Company has commitments for the funding (free carry) from Joint Venture partners for two offshore well up to US$65m (~A$95m). — The Company has had zero Lost Time Incidents (LTI’s) and zero Environmental Incidents I would like to expand a little on this summary and to provide some detail on what has been a very successful year for our Company. From the outset let me point to one of the significant achievements in the history of 3D Oil, the acquisition of VIC/P79 in the offshore Otway Basin, followed shortly thereafter by the farmout of the license with ConocoPhillips Australia (“COP”), comprising fantastic terms for 3D Oil. As I write this letter, we are currently nearing completion of the remaining agreements required to finalise the farm-in. The Company’s technical analysis prior to bidding for VIC/P79 allowed 3D Oil to develop an aggressive bid and achieve the ultimate success of securing the Permit. Our analysis of the permit indicates that it offers significant gas potential. This view is enhanced, in part by its proximity to the significant gas fields including Geographe and Thylacine. Shortly after being awarded VIC/P79 the Company negotiated a farm-in deal which included a US$35m (`A$50m) free carry for an exploration well and US$3m (`A$4.35m) cash consideration. This transaction follows our recent transaction with ConocoPhillips in T/49P. Arguably these farm-in agreements are among the best in the Australian oil and gas sector for almost two decades providing ~A$95m of value for 3D Oil based on today’s exchange rate. The result is that 3D Oil now has two funded wells in the Otway Basin due to be drilled by early 2025. This is consistent with the Company’s strategy to provide funding solutions by attracting quality Joint Venture partners and provide a catalyst for significant growth while maintaining a pathway for the ultimate goal of becoming an east coast gas producer. At a technical level the Company has already identified a drillable prospect within VIC/P79. The Vanguard prospect has a best estimate prospective of 160 bcf of gas (refer ASX Announcement dated 8 June 2022). This prospect has associated seismic amplitude anomalies which are comparable to anomalies encountered in fields drilled in the Otway basin that have achieved a 100% success rate over almost two decades. Additional amplitude supported features have also been recognized down-dip from the La Bella gas discovery and it’s becoming increasingly clear to 3D Oil that significant prospectivity remains to be uncovered in the Permit. The T/49P planned Sequoia 3D Seismic Survey was completed during November 2021, with the final versions of the processed data now being received from COP. While it is too early to map prospects on the data, all signs are very encouraging. We expect to have prospects delineated in the coming months. The Company believes that the T/49P permit is the last place on the east coast where significantly large gas reserves can potentially be uncovered which can be delivered economically to the east coast market. The drilling of the two upcoming exploration wells has come with the backdrop of a gas energy crisis that emerged on the east coast in the winter of 2022. In support of the 3D Oil gas exploration strategy the Australian Energy Market Operator (AEMO) has indicated [2022 Gas Statement of Opportunities] that gas is projected to maintain its importance in the Australian domestic energy mix to at least to the 2040s 2 Image courtesy of Shearwater VIC/P74 is located offshore in the Gippsland basin also forms a strategically important asset for 3D Oil with respect to the east coast gas market, having 1.8 tcf of best estimate prospective resources (refer ASX Announcement dated 16 February 2021). The recent withdrawal of Hibiscus from the 3D Oil Joint Venture now provides the Company with increased equity enabling 3D Oil to consider new farmout opportunities Adding to our two highly prospective offshore Otway blocks is the recent addition of the Caroline Field in the onshore Otway Basin. The acquisition of GSEL 759 represents an exciting gas storage opportunity for the Company thereby broadening the Company’s strategy within the rapidly changing east coast energy market. The license is ideally situated being located only 20km southeast of Mount Gambier and proximal to the South East Pipeline System. Over the next few months, the Company will undertake technical work to better understand the reservoirs’ suitability for gas storage applications, including storage capacity, reservoir deliverability and seal integrity, with a view to determining the most feasible business model from multiple gas storage and supply scenarios. As a longer-term strategy, WA-527-P is a very large permit in the rapidly emerging and prolific hydrocarbon province in the Bedout Sub- Basin. In contemporary times the uncovering a world class basin is extremely rare. The recent announcement by Carnarvon Energy Limited illustrated a plethora of highly prospective leads and prospects across the basin, with Starbuck and Flint prospects located directly adjacent to the 3D Oil WA-527-P boundary. During the year our permit’s potential was substantially upgraded with the significant Pavo oil discovery in the neighbouring Permit. The Pavo 1 exploration well encountered a significant light oil (~52°API) discovery within excellent reservoirs of the Caley Member, with 46m net pay (60m gross), 19% average porosity, 80% average oil saturation with high permeabilities of 100-1000 millidarcies reported. Pavo 1 de-risks uncertainties around source presence and hydrocarbon migration away from previous discoveries and towards the basin margin, supporting the likely migration to any erosional truncation leads in WA-527-P. ENERGY IN A GLOBAL CONTEXT I would like to now digress briefly and discuss the role of oil and gas in the world today – this provides important context for 3D Oil’s future. Hydrocarbons, including gas, supplied 83 per cent of all global energy in 2020 – surprisingly that number rose in 2021 by about 6 percent. It’s worth reminding ourselves that 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. Australia is completely dependent on gas, and coal, for ourselves, as well as for export income. Energy hungry Asia countries where economic growth is tied to power usage are dependent on Australian gas. In short, while the world is seeking to transition towards alternative energy, hydrocarbons are projected to have role to play in the ultimate energy mix. The global energy sector is currently changing at a pace never witnessed in history. It was just over 2 years ago that energy prices were the lowest in human history. At that time oil was trading at negative prices and the world enjoyed these prices across many sectors including the renewable energy manufacturing sector. Very few saw the speed of current energy crisis coming. What has occurred within the two-year period is extremely rapid increase in prices, particularly in the retail and wholesale downstream markets, reaching some of the highest prices in history. The average range between peak to trough pricing in some sectors around a 90% differential. The impact of this has a profound effect on the world from the European energy crisis to the emerging famine in many poorer countries around the world largely related to fertilizer and energy costs for food production. Further, these prices have only hastened the deindustrialization within the western world with China and counter intuitively Russia being the benefactors of these high energy prices. 3D Oil is well placed during this period and in the rapid transition to renewable energy. I am pleased to re-emphasize that 3D Oil shareholders are uniquely placed to benefit from the upside that the Company’s exploration strategy and current asset position offers. Finally, I would like to comment in a more general sense. As a small Australian company, we use all our efforts and will continue to act responsibly in our increasingly complex markets and operating environment. I would like to thank our shareholders, the communities, employees, contractors and business partners who continue to offers support and enable us to continue adding value and benefits for all. Noel Newell Executive Chairman 3 REVIEW OF OPERATIONS 4 WA-527-P, BEDOUT SUB-BASIN, OFFSHORE NORTHWEST SHELF Figure 1 – WA-527-P location, leads and Environmental Planning area for the Sauropod MC3D. Petroleum 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 of Australia (Figure 1). TDO is the Operator and holds 100% interest in the permit, which is situated approximately 50km along trend from the recent Pavo discovery (Carnarvon Energy 20%, Santos 80%). EXPLORATION RATIONALE The Bedout Sub-Basin is under-explored relative to surrounding prolific petroleum basins due to disappointing results with some of the first exploration wells in the 1970s and 1980s. The discovery of what was believed to be gas in the Phoenix wells in the 1980s also meant the basin was written off as gas-bearing for 32 years, until Phoenix South 1 discovered a series of light oil zones with the Barret sandstones in 2014. Subsequent appraisal wells also discovered gas condensate within the Middle Triassic Caley Member (Archer Formation). Roc-1 tested a faulted anticline up-dip from Phoenix South and discovered gas-condensate within sands of the Caley Member also. Dorado-1 was drilled up-dip from Roc in 2018 and was the first test of a new stratigraphic play, leading to the discovery of the largest oil field in Australia over the last 30 years. Dorado has fuelled a resurgence of exploration activity in the basin, hosting 162 MMbbls of liquids and 748 Bcf of gas within multiple reservoirs of the Middle Triassic Archer Formation, including the Caley, Baxter, Crespin and Milne members. 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. These are excellent results for reservoirs buried greater than 4000m depth. “Pavo 1 is a game changer for the prospectivity of WA-527-P, where the Caley play shared many of the same pre-drill risks as Pavo” 5 Figure 2 – Comparison of undrilled prospectivity in the under explored Bedout Sub-Basin with the highly explored Northern Carnarvon Basin. Inset bottom right creaming curve1 courtesy of Rystad Energy ECube June 2020, Rystad Energy Research and Analysis. The exploration potential within the Bedout Sub-Basin is best summarised by Figure 2, which compares the undrilled leads in the Bedout Sub-Basin with the highly explored Northern Carnarvon Basin to the southwest. Exploration has progressed from the basin centre towards the margin, testing the extent of the petroleum system with each new well. The highly anticipated Pavo 1 and Apus 1 exploration wells in March/April 2022 were the next wells to step out towards the basin margin and further support the Company’s long held view that the region hosts a prolific petroleum system. Pavo-1 intersected 46m net pay (60m gross) of light oil (~52° API) within the Caley Member. Log analysis of Pavo-1 indicates excellent reservoir quality with 19% average porosity, 80% average oil saturation and permeabilities ranging from 100-1000 millidarcies. Similar excellent reservoir quality can be anticipated within WA-527-P, where any drill targets defined by the planned Sauropod MC3D Seismic Survey will be located at similar depths. The Pavo-1 discovery provides significant uplift in relation to the prospectivity of WA-527-P, where the Caley play shared many of the same pre-drill risks as Pavo. Pavo-1 de-risks uncertainties around source 6 presence and hydrocarbon migration away from existing discoveries. The discovery highlights the existence of a new charge cell on the eastern side of a structural ridge that extends from Roc to Dorado. The Roc South-1 dry well suggests migration from the Dorado charge cell hasn’t crossed this ridge to charge Pavo structure. A new charge cell east of the Roc-Dorado ridge supports migration towards the basin margin and any erosional truncation leads in WA-527-P (Figure 3). Pavo-1 also confirms the presence and effectiveness of the Hove Member top/ lateral seals along trend from WA-527-P, where the top seal is thinning out of the basin. Importantly the Pavo-1 discovery has also indicated that small structural closures (5-6km2) form an important part of exploration portfolios in the region, hosting a volume of 43 MMbbls of high-quality oil (gross 2C). Despite the commercial failure of the Apus-1 exploration well, the Company believes there is a strong positive take away for WA-527-P. The Carnarvon Energy ASX release states that “while hydrocarbons were observed in the well a commercial hydrocarbon pool has not been discovered”. The Apus trap is an isolated remnant closure formed by the Dorado/ Apus canyons and top/lateral sealed by the transgressive Hove Member shales. These canyons prevent the migration of hydrocarbon from the Dorado/Roc charge cell and the only way to provide hydrocarbons to Apus structure is from a deeper, previously untested source rock. The presence of any hydrocarbons at Apus points to a deeper expelling source rock that may extend into the WA-527-P permit. Carnarvon attributed well failure to a lack of sufficient quantity of hydrocarbons to form a commercial pool, or the inability to retain significant hydrocarbons with the closure. The Pavo-1 and Apus-1 wells de-risk some of the critical elements within the Caley Member play in WA-527-P. Traps are the final piece of the puzzle. The potential for analogous stratigraphic and structural traps to Dorado and Pavo, respectively, has been delineated along the western margin of WA-527-P utilising reprocessed legacy 2D seismic (Figure 4). The planned Sauropod MC3D Seismic Survey will support the definition of any potential traps and provide the means to capitalise on TDOs early entry into what remains a highly under explored basin. 1 Northern Carnarvon Basin (blue curve), Bonaparte Basin (lower green curve), Browse Basin (upper green curve), Bedout Sub-Basin (red curve). Figure 3 – Pavo demonstrates the presence of a new charge cell operating in the Bedout Sub-Basin. Figure 4 – Amplitude anomaly (full stack) on reprocessed 2D seismic, truncated by a potential erosional channel system within WA-527-P (red arrows delineate edges of channel). “Pavo and Apus de-risk some of the critical elements within the Caley Member play in WA-527-P. Traps are the final piece of the puzzle.” 7 ACTIVITIES Over the course of the year, 3D Oil progressed with plans to acquire the Sauropod MC3D in the next available acquisition window and entered discussions with seismic company CGG to acquire the survey as multi-client data. On 6 September 2021, the Sauropod MC3D Environment Plan (EP) was re-submitted for a one-month public comment period. The EP delineated the same acquisition parameters as previously proposed, including a maximum full fold acquisition area of 3447km2 (Figure 1). The Company was subsequently notified by NOPSEMA (National Offshore Petroleum Safety and Environmental Management Authority) of the acceptance of the EP on 16th February 2022. Despite the award of the EP, the Company was disappointed to miss the January- May (inclusive) 2022 acquisition window. The acquisition was contingent on the availability of an appropriate vessel relative to the timing of approval of the EP. Unfortunately, the award of the EP came after the deadline for the procurement of a vessel had already passed. The only available vessel, the Geo Coral, had already been contracted by Santos and Korea National Oil Company for other surveys. 3D Oil remains committed to acquiring the Sauropod MC3D Seismic Survey, which underpins the WA-527-P exploration strategy. The survey has several objectives, however, is primarily aimed at determining the potential for remnant traps associated with a Triassic erosional channel system that is analogous to the trapping mechanism for the nearby Dorado discovery. 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 MC3D will enable the Company to develop a risked and ranked leads and prospects portfolio to attract favourable farm-in terms in fulfillment of the primary term work program. The Company is currently preparing to resubmit the previously approved EP for an acquisition window covering January- May (inclusive) 2023, or January-May (inclusive) 2024. As recommended by NOPTA (National Offshore Petroleum Titles Administrator), the Company will apply for a 2-year EP and aims to re- submit the revised EP in Q3, 2022. To this end, re-engagement with NOPSEMA and key stakeholders has commenced. The Company would ideally acquire the survey in 2023, however based on the availability of seismic vessels in Australia, a two-year period for the EP is prudent. The Company has launched a renewed farmout campaign following the Pavo oil discovery, which has significantly upgraded the prospectivity of the Caley Sandstone play in WA-527-P (Refer TDO ASX Announcement 24 March 2022). The Company has observed significant renewed interest from the farm-in market and continues to hold active discussions and data rooms with interested farm-in candidates. PROSPECTIVITY Mesozoic Leads The Company 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 Salamander, with a Best Estimate Prospective Resource of 86 MMbbls and 190 MMbbls respectively. In fact, Salamander is the third largest undrilled Triassic closure in the Bedout Sub-Basin. The Sauropod MC3D will allow the Company to delineate the structural closure of these features more accurately, and thus update the prospective resource estimates. Palaeozoic Leads The Company 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 MC3D will provide imaging for the largest of these features located in the north of the permit. Table 1: WA-527-P Prospective Resource Estimate (MMbbls) Recoverable Oil (100% Net Prospective Resources to TDO. Refer to ASX announcement 26-Feb-18) Prospect Salamander Jaubert Whaleback WA-527-P Total Status Low Lead Lead Lead 57 17 16 90 Best 191 72 87 High 713 205 219 349 1,138 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. 8 T/49P, OTWAY BASIN, OFFSHORE TASMANIA Figure 5 – T/49P exploration permit relative to Otway Basin discoveries and infrastructure. Note the recently acquired Sequoia 3D MSS covers prospective leads in the central corridor. TDO holds 20% interest in the T/49P petroleum exploration permit, which is operated by ConocoPhillips Australia. The permit is situated west of King Island, Tasmania and covers 4,960 km2, a massive and under explored area of the offshore Otway Basin (Figure 5). The Otway Basin covers an area of ~150,000 km2 along the southern margin of Australia and has been an important supplier of gas to the east coast since the 1980s. T/49P is located adjacent to the producing Thylacine and Geographe gas fields (Beach Energy operator, ASX: BPT) and is optimally located to contribute much needed additional resources to the east coast market. 9 The survey was completed in full compliance with stringent Environmental Plan (EP) conditions, including all marine mammal and invertebrate management requirements, and fulfills ConocoPhillips’ commitment to acquire 3D seismic over a minimum area of 1580 km2 within the Permit, as per the Farmout Agreement (“FOA”) and TDO ASX Announcement on 18 Dec 2019. No costs were incurred by TDO towards the acquisition of the survey. In combination with the Flanagan 3D MSS, acquired by TDO in 2014, the Sequoia 3D MSS will allow the Joint Venture to evaluate the full potential of the permit with high- quality, modern 3D seismic. Processing of the Sequoia 3D MSS is currently under way and a preliminary fast-track volume was received in July 2022. A significant uplift in data quality is anticipated with the continued progression of processing workflows towards a final volume. A full evaluation of the potential of the permit, including seismic attribute analysis, will be possible once the final volume has been received. Upon interpretation of the Sequoia 3D MSS and high grading of potential gas targets, COPA may elect to drill an exploration well in fulfillment of the current Year 6 work program. As per the FOA, TDO will be carried for up to US$30 million in drilling costs after which it will contribute 20% of drilling costs in line with its interest in the Permit. EXPLORATION RATIONALE T/49P 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 the 974 km2 Flanagan 3D Marine Seismic Survey (MSS), while the central corridor is covered by 1700km2 of the newly acquired Sequoia 3D MSS. 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. TDO management believes the south-east Australian gas market will be strong in coming years as existing gas production in both the Gippsland and Otway Basin declines. 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/49P 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 and development activity in the basin. Beach Energy has just completed a seven (7) well drilling campaign that has resulted in the Artisan-1 gas discovery and supported an increase in average daily Otway Gas Plant production by 46% to 94 TJ/day gross (Beach Energy Annual Report 2022). Beach Energy has announced an FY24 drilling program around the development of Artisan and La Bella, potentially followed by exploration drilling in FY25 near the Enterprise gas discovery. Cooper Energy (ASX:COE) recently announced a targeted Q3 FY23 Final Investment Decision (FID) for its Otway Phase 3 development project. This involves the development of the Annie gas field, with first gas being targeted before winter 2025 in combination with potential exploration drilling at the Elanora Prospect. Yet another compelling indication of the importance of the Otway Basin to future east coast gas supply is the expansion of ConocoPhillips’ title holding in the Otway Basin, by way of farm-in to TDO’s newest acreage, VIC/P79 exploration permit. ACTIVITIES This financial year saw the highly anticipated acquisition of the Sequoia 3D Marine Seismic Survey (MSS). The Environmental Plan (EP), submitted by Operator ConocoPhillips Australia, was accepted by NOPSEMA (National Offshore Petroleum Safety and Environmental Management Authority) on 10 August 2021 and was valid from 10 August 2021 – 31 October 2021. The Shearwater vessel Geo Coral commenced acquisition of the Sequoia 3D MSS in late August and safely completed the acquisition at midnight on 31 October 2021, in accordance with the approved EP from NOPSEMA. The Sequoia 3D MSS was hampered by unprecedented weather in Bass Strait early in the acquisition window which, in addition to further EP conditions, resulted in a total acquisition area of approximately 1700km2, less than the approved 2450km2. Despite this, prioritisation of the survey across the central corridor has yielded coverage across the most prospective leads (Figure 5), including all pre-existing leads (excluding Flanagan). “TDO management believes the south-east Australian gas market will be strong in coming years as existing gas production in both the Gippsland and Otway Basin declines” 10 PROSPECTIVITY FLANAGAN PROSPECT Figure 6 – Modelled gas expulsion and migration From a geological standpoint, one of the key reasons T/49P was acquired was due to its unique position with 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 interprets 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/49P (Figure 6). 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 27th 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. “TDO recognized the potential for the shortfall in gas supply to south- east Australia as early as 2012 and acquired the T/49P exploration permit on that basis” 11 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 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 (BCF) Gross Recoverable Gas (Net TDO Recoverable Gas) (20% Net Prospective Resources to TDO. Refer to ASX announcement 27-Jul-17) Location Flanagan Seal Rocks Whistler Point British Admiral Harbinger Munro (in-permit) T/49P Total Status Prospect Lead Lead Lead Lead Lead Low 530 (106) 950 (190) 820 (164) 370 (74) 330 (66) 40 (8) Best 1340 (268) 4640 (928) 2040 (408) 1030 (206) 790 (158) 190 (38) High 2740 (548) 10640 (2128) 8950 (1790) 4450 (890) 1430 (286) 570 (114) 3040 (608) 10030 (2006) 28780 (5756) 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 12 VIC/P79, OTWAY BASIN, OFFSHORE VICTORIA 3D Oil holds 100% interest in the VIC/P79 exploration permit, awarded from the 2020 Offshore Petroleum Exploration Acreage Release however the Company is currently in the process of farming down to COPA. The permit covers 2,575km2 of the offshore Otway Basin and is located adjacent to the producing Thylacine and Geographe gas fields (Operated by Beach Energy Limited (ASX: BPT)) and the La Bella gas discovery (Figure 8). The permit builds on a strong portfolio of leads and prospects already defined in nearby T/49P (owned 20% TDO), which will likely further grow after the processing and interpretation of the Sequoia 3D Marine Seismic Survey (MSS), recently acquired by operator ConocoPhillips Australia (COPA). In conjunction with T/49P, the Company has now strategically gained exposure to >60% of Otway Basin exploration by area. EXPLORATION RATIONALE Exploration permit VIC/P79 (Figure 8) covers a large area with little exploration drilling, with water depths ranging from 100-200m. The eastern half of the permit lies within the Shipwreck Trough and is proximal to the largest gas discoveries in the basin, Thylacine and Geographe. In addition, the La Bella gas discovery flanks the permit to the north on the margin of the Mussel Platform, pointing to a rich-gas prone petroleum system operating within the permit. TDO bid aggressively in the Offshore Acreage Release to secure the sought-after permit having recognised the previously overlooked Vanguard Prospect in the eastern half of the acreage, characterised by Direct Hydrocarbon Indicators (DHIs) such as flat spots. Accordingly, TDO bid a well in the primary term, which was designed to progress Vanguard to drill- ready status. The acquisition of a DHI supported prospect situated within the proven gas fairway of the region greatly upgrades the Company’s position within the Otway Basin. The basin has witnessed a significant success rate for almost two decades due to the identification of DHIs. The area to the west of the Nautilus-A1 and Triton-1 wells is under explored, with no exploration wells and 2D seismic of varying quality. In-house regional evaluation suggests this area may also host prospective reservoir and seal sections, the potential extension of existing plays Figure 8 – VIC/P79 location relative to surrounding fields and infrastructure to the northeast. Proximal discoveries include Henry, Netherby and Pecten fields. The secondary term will focus on the acquisition and processing of a new 1000km2 3D seismic survey in the west, with the intention of searching for additional closures. ACTIVITIES VIC/P79 was awarded in February 2022 and shortly thereafter TDO embarked on an accelerated farmout campaign, given early expressions of interest in the permit and the well commitment in the primary term. Preliminary seismic interpretation has been ongoing through this time, leading to the identification of the Defiance and Trident leads, both exhibiting amplitude conformance with structure. Please refer to ASX Announcement dated 8 June 2022 for further information. On 30 June 2022, the Company executed a Farmout Agreement (“FOA”) with ConocoPhillips Australia SH2 Pty Ltd (“ConocoPhillips Australia”) in relation to the offshore Victorian Exploration Permit VIC/P79 (TDO ASX Announcement, 1 July 2021). Under the terms of the FOA, ConocoPhillips Australia will acquire an 13 Figure 9 – Lower Waarre depth map of the Vanguard Prospect showing the location and extent of the observed flat spot. 80% interest in the Permit and operatorship in exchange for an upfront payment of USD$3 million. ConocoPhillips Australia will also undertake to drill an exploration well as required by the permit’s Primary Term minimum work commitment (currently required by February 2025). The Company will be carried for up to USD$35 million in well costs, above which it will contribute 20% of costs in line with its interest in the Permit. At the date of this report, agreement is subject to conditions precedent, including the agreement and signing of a Joint Operating Agreement by both parties and required government/ regulatory approvals. This second major deal with ConocoPhillips Australia is an outstanding result for the Company, especially given the timeline from permit award to farmout. It should be noted that the FOA is subject to conditions precedent, including the agreement and signing of a Joint Operating Agreement by both parties and required government/ regulatory approvals. PROSPECTIVITY Vanguard Gas Prospect Vanguard is an east-west trending tilted fault-block trap located on the eastern side of VIC/P79 (Figure 9), approximately 5km northwest of Geographe Field between Geographe and the La Bella gas discovery. Vanguard is constrained by the La Bella and Investigator 3D seismic surveys and seismic interpretation shows the structure hosts stacked reservoir sands of the Waarre Formation. The structure’s potential was first realised through the identification of a flat spot within the Lower Waarre (Figure 10). DHIs have been observed on the Investigator 3D MSS from three stratigraphic levels across the structure, ranging in depth from approximately 2200-2400mSS. Vanguard boasts a strong amplitude response, and potential Amplitude Variation with Offset (AVO), which is common to adjacent gas discoveries and producing fields and can indicate the presence of hydrocarbons. In fact, these gas signatures have been identified on 3D seismic data across most offshore Otway Basin gas discoveries throughout the last two decades. Defiance and Trident Leads Both Defiance and Trident leads are tilted fault block closures (Figure 11) directly down-dip from the La Bella gas discovery to the east and similarly exhibit amplitude conformance with structure (Figure 12). Defiance exhibits amplitude conformance with structure at both the Upper Waarre and Lower Waarre horizons, where the Upper Waarre horizon conforms with the deeper, larger gas zone at La Bella-1. The Defiance structure has an areal closure of 1.1-1.6km2, however, approximately 50% of the Defiance structure lies outside of the permit to the north and east (Figure 11). Trident has an areal closure of 1.9km2 and exhibits amplitude conformance with structure at the Lower Waarre horizon only, what is commonly referred to as the Waarre A reservoir at in-board wells, based on the La Bella-1 well-tie. Amplitude conformance with structure is considered one of the most reliable and robust Direct Hydrocarbon Indicators (DHIs), representing buoyancy driven fluid phase boundaries (i.e., gas-water contacts), and significantly reduces uncertainty around the presence of hydrocarbons. “The acquisition of a DHI supported prospect situated within the proven gas fairway of the region greatly upgrades the Company’s position within the Otway Basin” 14 Figure 10 – Vanguard structure on the Investigator 3D MSS with flat spot at the Lower Waarre. Figure 11 – Lower Waarre TWT structure map showing Defiance and Trident leads. 15 Figure 12 – Lower Waarre RMS amplitude map showing strong conformance of amplitude with structure. Note amplitudes extend beyond the permit towards the north. Table 3: VIC/P79 Prospective Resources Estimate Gross Recoverable Gas (Bcf) (100% Prospective Resources to TDO2. Refer to ASX announcement 8-Jun-22) Lead/Prospect Vanguard Trident Defiance La Bella East La Bella SW VIC/P79 Total Status Prospect Lead Lead Lead Lead Low 52.5 19.5 17.2 17 12 118.2 Best 161.5 37.2 32.5 37.5 29 297.7 High 425 65 59.9 65.5 54 669.4 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. 2 Prospective resource estimates will reduce from 100% to 20% net to TDO on NOPTA approval of the FOA with ConocoPhillips Australia. 16 “This second major deal with ConocoPhillips Australia is an outstanding result for the Company, especially given the timeline from permit award to farmout”. Figure 13 – VIC/P74 Location VIC/P74, GIPPSLAND BASIN OFFSHORE VICTORIA 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. The VIC/P74 petroleum exploration permit was awarded to TDO on 26th July 2019 and covers an area of 1,006 km2 of the offshore Gippsland Basin, in shallow water depths ranging up to 70m (Figure 13). The Company will hold 100% in the permit pending the withdrawal of Hibiscus Petroleum in 2022. 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 13). 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. 17 ACTIVITIES VIC/P74 entered Year 3 of the primary work program on 26 July 2021. Early in the year, the Company released an update to the market on Prospective Resource estimates within the permit (refer to ASX announcement dated 7 October 2021). This update was based on stratigraphic, seismic interpretation and depth conversion studies in the deeper Emperor Subgroup play where additional gas prospectivity has been identified at several existing leads, including Oarfish and Megatooth. Importantly, these closures are located along strike to the gas sands at the Omeo discovery. Oarfish is now the largest un-risked gas target in the permit (Figure 14), having a total best estimate prospective resource of 544 Bcf, up from 338 Bcf. The lead is situated 2km to the east of Omeo 1A and reservoir/seal pairs are anticipated to be similar. Oarfish essentially has the same trapping configuration as the Omeo structure, which has hydrocarbons at equivalent levels based on log analysis and RFT recovery of water and gas with a thin film of oil/condensate. Megatooth now has a total best estimate recoverable prospective resource of 465 Bcf (Figure 14), up from 204 Bcf. The lead is well situated relative to the kitchen underlying Bream towards the northeast and migration can be demonstrated by gas-condensates intersected within the Lower Latrobe Group at Omeo 1A. Emperor gas sands at the Omeo wells lie within 1km of Megatooth. Having now completed the primary term, the next stage of exploration in VIC/P74 will involve the acquisition or purchase of modern 3D seismic data to assist with maturing the best potential lead(s) to prospect status. Prior to entry into the secondary term, where obligations are year-to-year and entry in the following year is optional, the Joint Venture has completed a strategic review. Accordingly, Hibiscus Petroleum have elected to transfer their 50% participating interest back to 3D Oil. The Joint Venture applied for a Transfer of Title in July, which is currently under review. 18 Figure 14 – Top Golden Beach Subgroup depth map with identified closures (purple outlines) The Company recognises the potential for VIC/P74 to help address the impending east coast gas supply shortage and remains committed to fulfilling the secondary work program. The Year 4 work commitments are designed to assist with lead maturation and include the acquisition or purchase of 200km2 of modern 3D seismic data, as well as seismic interpretation, depth conversion, inversion and AVO. The Joint Venture have applied to NOPTA for a ‘Variation of Title Conditions’ before entry into Year 4, seeking to alter aspects of the secondary work program. This application is currently under review. TDO has been approached by interested parties over the course of the year and is continuing the farmout campaign. The Joint Venture is seeking the best possible terms to facilitate the next stages of exploration, including seismic acquisition and drilling. “The next stage of exploration in VIC/ P74 will involve the acquisition or purchase of modern 3D seismic data to assist with maturing the best potential lead(s) to prospect status” 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. PROSPECTIVITY Bigfin Lead Bigfin lies in shallow waters (~80m) directly adjacent to the world class Kingfish structure. The trap is a two-way dip closure (maximum closing contour) at the top Golden Beach Subgroup (~2950m TVDSS) and has a large areal closure (~29km2) and vertical relief (up to 230m). Imaging of the trap, including faults and deeper reflectivity, has been improved through the 3D seismic reprocessing completed by CGG (Figure 15). Detailed mapping and depth conversion of this data supports a prospective best estimate gas resource of 534 Bcf (502 Bcf in permit). Overlying shallower closures were 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. Figure 15 – Comparison between legacy and CGG 3D reprocessed seismic at Bigfin Lead “The Company recognises the potential for VIC/ P74 to help address the impending east coast gas supply shortage and remains committed to fulfilling the secondary work program” 19 Table 4: VIC/P74 Prospective Resources Estimate (Bcf) Recoverable Gas (Net TDO Recoverable Gas) (50% Net Prospective Resources to TDO3. Refer to ASX announcement 07-Oct-21). Lead/Prospect Status Oarfish Bigfin Megatooth Stargazer VIC/P74 Total Lead Lead Lead Lead Low 303 (152) 296 (148) 259 (130) 192 (96) Best 544 (272) 502 (251) 465 (233) 344 (172) High 918 (459) 783 (392) 784 (392) 564 (282) 1050 (526) 1855 (928) 3049 (1525) Table 5: VIC/P74 Prospective Resources Estimate (MMbbls) Recoverable Condensate (Net TDO Recoverable Condensate) Lead/Prospect Status Oarfish Bigfin Megatooth Stargazer VIC/P74 Total Lead Lead Lead Lead Table 6: VIC/P74 Prospective Resources Estimate (MMbbls) Recoverable Oil (Net TDO Recoverable Oil) Lead/Prospect Megatooth Oarfish VIC/P74 Total Status Lead Lead Low 4 (2) 2 (1) 4 (2) 3 (1.5) 13 (6.5) Low 28 (14) 23 (11) 51 (26) Best 19 (9) 19 (10) 16 (8) 12 (6) 66 (33) Best 58 (29) 40 (20) 98 (49) High 60 (30) 39 (20) 51 (26) 37 (19) 187 (95) High 107 (54) 71 (35) 178 (89) 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. VIC/P57, GIPPSLAND BASIN OFFSHORE VICTORIA Exploration Permit VIC/P57 lies in shallow waters of the northwest offshore Gippsland Basin, where it covers 246 km2 (Figure 13). TDO holds a 24.9% interest in VIC/P57, which was renewed by the Joint Venture in 2018 for a further five years, with the primary term designed to de-risk and high grade the prospect inventory and ultimately progress prospects to ‘drill- ready’ status. VIC/P57 entered the final year of the Primary Term on 7 March 2020. The JV subsequently received a 12-month Suspension and Extension to the Primary Term, extending the Primary Term to 6 March 2022. ACTIVITIES The JV has completed the guaranteed primary term (Years 1-3) work program commitments and has worked diligently to attract a potential partner in the VIC/P57 exploration permit, ahead of the Year 4 work commitment for one exploration well. After a commercial review of the permit, the JV lodged a ‘Consent to Surrender Title’ application with NOPTA (National Offshore Petroleum Titles Administrator) for the entirety of the VIC/P57 petroleum exploration permit. As of 11 August 2022, VIC/P57 has been officially surrendered, as published in the Australian Government Gazette. 20 3 The Joint Venture submitted a Transfer of Title application to NOPTA in July 2022. Once approved, this will change to 100% Prospective Resources to TDO. DIRECTORS’ REPORT 21 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 2022. 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 Mr Trevor Slater (appointed on 15 November 2021) PRINCIPAL ACTIVITIES During the financial year the principal continuing activities of the Company consisted of exploration and development of upstream oil and gas assets. DIVIDENDS There were no dividends paid or declared during the current or previous financial year. The Consolidated Entity does not have franking credits available for subsequent financial years. REVIEW OF OPERATIONS The loss for the Consolidated Entity after providing for income tax amounted to $1,147,179 (30 June 2021: $1,142,095). Refer to the detailed Review of Operations preceding this Directors' Report. FINANCIAL POSITION The net assets decreased by $1,135,294 to $6,474,226 at 30 June 2022 (30 June 2021: $7,609,520). During the year the Consolidated Entity spent a net amount after reimbursements of $715,100 (2021: $851,721) on exploration, mainly in relation to WA/527P, T49/P and VIC/P74. The working capital position of the Consolidated Entity as at 30 June 2022 is $137,577 (30 June 2021: $2,067,184). The Consolidated Entity incurred net operating cash outflows of $992,645 (2021: $1,048,675). The cash balances as at 30 June 2022 was $1,243,195 (2021: $3,048,802). 22 RISKS AND UNCERTAINTIES Commodity price risks The Company is subject to risks that are specific to the Company and the Company’s business activities, as well as general risks. Future funding risks The Company is involved in exploration and development of upstream oil and gas assets and is yet to generate revenues. The Company has a cash and cash equivalents balance of $1,243,195 and net assets of $6,474,226 as at 30 June 2022. The Company may require substantial additional financing in the future to sufficiently fund exploration commitments and its other longer-term objectives. As the Company is still in the early stages of exploration it has the ability to control the level of its operations and hence the level of its expenditure over the next 12 months. However, the Company's ability to raise additional funds will be subject to, among other things, factors beyond the control of the Company and its Directors, including cyclical factors affecting the economy and share markets generally. If for any reason the Company was unable to raise future funds, its ability to meet the exploration commitments and future development would be significantly affected. The Directors regularly review the spending pattern and ability to raise additional funding to ensure the Company’s ability to generate sufficient cash inflows to settle its creditors and other liabilities. Joint Venture Operations Risks The Company participates in a number of joint ventures for its business activities. This is a common form of business arrangement designed to share risk and other costs. Under certain joint venture operating agreements, the Company may not control the approval of work programs and budgets and a Joint Venture Partner may vote to participate in certain activities without the approval of the Company. As a result, the Company may experience a dilution of its interest or may not gain the benefit of the activity, except at a significant cost penalty later in time. Failure to reach agreement on exploration, development and production activities may have a material impact on the Company’s business. Failure of the Company’s Joint Venture Partner’s to meet financial and other obligations may have an adverse impact on the Company’s business. The Company works closely with its Joint Venture Partner’s. Future value, growth and financial conditions are dependent upon the prevailing prices for oil and gas. Those prices are subject to fluctuations and are affected by numerous factors beyond the control of the Company. Prospective resources estimate risks Oil and gas resource estimates are expressions of judgement based on knowledge, experience and industry practice. These estimates may alter significantly or become uncertain when new information becomes available and/or there are material changes of circumstances which may result in the Company altering its plans. This could have a positive or negative effect on the Company’s operations. Other risks may affect the resource estimate, for example, commodity price movements. Environmental and social risks The business of exploration, development and production, involves a variety of risks which may impact the community and the environment. The Company’s exploration and development activities are subject to local, state, and federal environmental laws and regulations. Oil and gas exploration and development can be potentially environmentally hazardous, giving rise to substantial costs for environmental rehabilitation, damage control and losses. The legal framework governing this area of law is complex and constantly developing. There is a risk that the environmental regulations may become more onerous, making the Company’s operations more expensive or causing delays. It is the Company’s policy to conduct its activities to the highest standard of environmental obligation. There is no assurance that new environmental laws, regulations or stricter enforcement policies, if implemented, will not oblige the Company to incur significant expense and undertake significant investment, which could have a material adverse effect on its business, financial conditions and results of operations. The long-term viability of the Company is closely associated to the wellbeing of the communities and environments in which the Company conduct operations. At any stage, the Company’s operations and activities may have or be seen to have significant adverse impacts on communities and environments. In these circumstances, the Company may fail to meet the evolving expectations of our stakeholders (including investors, governments, employees, suppliers, customers and community Impact of COVID-19 The global impact of the COVID-19 pandemic, and the advice and responses from health and regulatory authorities, is continuously evolving. The global economic outlook is facing uncertainty due to the COVID-19 pandemic which has had and may continue to have a significant impact on capital markets and share prices. To date, COVID-19 has affected equity markets, governmental action, regulatory policy, quarantining, self-isolations and travel restrictions. These impacts are creating risks for the Company's business and operations in the short to medium term. The Company has in place business continuity plans and procedures to help manage the key risks that may cause a disruption to the Company's business and operations, but their adequacy cannot be predicted. The Company's Directors are closely monitoring the situation and considering the impact on the Company’s business from both a financial and operational perspective. Regulatory risk The Company operates in a highly regulated environment and complies with regulatory requirements. There is a risk that regulatory approvals are withheld or take longer than expected, or that unforeseen circumstances arise where requirements may not be adequately addressed in the eyes of the regulator and costs may be incurred to remediate perceived non- compliance and/or obtain approval(s). The Company’s business or operations may be impacted by changes in personnel and Governments, or in monetary, taxation and other laws in Australia or overseas. The Company’s permits and activities may be subject to extensive regulation by local, state and federal governments. There is no assurance that future government policy will not change, and this may adversely affect the long-term prospects of the Company. Future changes in governments, regulations and policies may have an adverse impact on the Company. SIGNIFICANT CHANGES IN THE STATE OF AFFAIRS 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. On 7 October 2021, the Consolidated Entity announced an update surrounding the delineation of additional prospectivity within the VIC/P74 exploration permit. This included an update to the Prospective Resources estimates for Leads and Prospects released to the market on 16 February 2021. On 29 October 2021, the Consolidated Entity announced the appointment of Mr Trevor Slater as a Non-Executive Director, with his appointment effective at the conclusion of the Company’s Annual General Meeting on 15 November 2021. In addition, Ms Melanie Leydin stepped down as Joint Company Secretary, effective 29 October 2021, with Mr Stefan Ross continuing in the officeholder position as sole Company Secretary. members) whose support is needed to realise our strategy and purpose. This could lead to loss of stakeholder support or regulatory approvals, increased taxes and regulation, enforcement action, litigation or class actions, or otherwise impact our licence to operate and adversely affect our reputation, fund raising capability, ability to attract and retain talent, operational continuity and financial performance. Exploration and development risks Exploration is a speculative activity with an associated risk of discovery to find oil and gas in commercial quantities, and a risk of development. If the Company is unsuccessful in locating and developing or acquiring new reserves and resources that are commercially viable, this may have a material adverse effect on future business, results of operations and financial conditions. Oil and gas exploration is a speculative endeavour and the nature of the business carries a degree of risk associated with failure to find hydrocarbons in commercial quantities or at all. The Company utilises well-established prospect evaluation, ranking methodologies and experienced personnel to manage exploration and development risks. Reliance on key personnel The Company’s success depends to a significant extent upon its key management personnel, as well as other management and technical personnel including those employed on a contractual basis. The loss of the services of such personnel or the reduced ability to recruit additional personnel could have an adverse effect on the performance of the Company. The Company maintains a mixture of permanent staff and expert consultants to advance its programs and ensure access to multiple skill sets. The Company reviews remunerations to human resources regularly. IT system failure and cyber security risks Any information technology system is potentially vulnerable to interruption and/ or damage from a number of sources, including but not limited to computer viruses, cyber security attacks and other security breaches, power, systems, internet and data network failures, and natural disasters. The Company is committed to preventing and reducing cyber security risks through outsourced the IT management to a reputable services provider. 23 MATTERS SUBSEQUENT TO THE END OF THE FINANCIAL YEAR On 2 September 2022, the Consolidated Entity announced that the South Australia Department of Energy and Mining has awarded the Company the GSEL 759 Gas Storage Exploration Licence in onshore Otway Basin. The licence covers an area of 1.02km2, centrally located around the plugged and abandoned Caroline-1 wellhead, over part of the now depleted Caroline Field, originally used for the production of carbon dioxide in the Otway Basin. The Field is potentially suitable for the storage of hydrogen, natural gas, or carbon dioxide. The acquisition of GSEL 759 represents an exciting development opportunity for the Company in broadening 3D Oil’s strategy in the rapidly changing East Coast energy market. No other matter or circumstance has arisen since 30 June 2022 that has significantly affected, or may significantly affect the Consolidated Entity's operations, the results of those operations, or the Consolidated Entity's state of affairs in future financial years. LIKELY DEVELOPMENTS AND EXPECTED RESULTS FROM OPERATIONS The Consolidated Entity will continue to pursue its exploration interest in INFORMATION ON DIRECTORS Mr Noel Newell Executive Chairman Qualifications B App Sc (App Geol) Experience and expertise Noel Newell holds a Bachelor of Applied Science and has over 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. — VIC/P74 in the offshore Gippsland Basin of Victoria; — T49P in partnership with Conoco Phillips Other current directorships None Australia SH1 Pty Ltd; Former directorships (last 3 years) — WA/527-P in the Roebuck Basin of None Western Australia: — VIC/P79 in partnership with Conoco Phillips Australia SH2 Pty Ltd: and Special responsibilities None — GSEL759 in the Otway Basin of South Interests in shares Australia. 44,381,998 ordinary fully paid shares. Interests in options None 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 2022. On 4 February 2022, the Consolidated Entity announced that the National Offshore Petroleum Titles Administrator (“NOPTA”) has awarded the Consolidated Entity the VIC/P79 exploration permit in the offshore Otway Basin. The 2,576km2 permit is located adjacent to the largest gas fields in the offshore Otway Basin, Thylacine and Geographe, and contains the highly prospective Vanguard Prospect. The Permit was awarded with a minimum work commitment that includes one exploration well. The acquisition of VIC/P79 accelerates 3D Oil’s strategy to be a significant east coast gas producer and compliments our Otway Basin Joint Venture in T/49P with ConocoPhillips. On 8 June 2022, the Consolidated Entity announced an update surrounding the delineation of additional prospectivity within the VIC/P79 exploration permit, Otway Basin, Victoria. This included an update to the prospective resource estimates for leads and prospectus released to the market on 4 February 2022. On 30 June 2022, the Company and ConocoPhillips Australia SH2 Pty Ltd (“ConocoPhillips Australia”) has executed a Farmout Agreement (“FOA”) in relation to the offshore Victorian Exploration Permit VIC/P79 (“Permit”), located in the Otway Basin. Under the terms of the FOA, ConocoPhillips Australia will acquire an 80% interest in the Permit and operatorship in exchange for an upfront payment of USD$3 million (~AUD$4.35 million). ConocoPhillips Australia will also undertake to drill an exploration well as required by the Permit’s Primary Term minimum work commitment (currently required by February 2025). The Consolidated Entity will be carried for up to USD$35 million (~AUD$50.75 million) in well costs, above which it will contribute 20% of costs in line with its interest in the Permit. It should be noted that the FOA is subject to conditions precedent, including the agreement and signing of a Joint Operating Agreement by both parties and required government / regulatory approvals. At the date of this report, agreement is subject to conditions precedent, including the agreement and signing of a Joint Operating Agreement by both parties and required government/ regulatory approvals. There were no other significant changes in the state of affairs of the Consolidated Entity during the financial period. 24 Mr Leo De Maria Non-Executive Director Trevor Slater (appointed 15 November 2021) COMPANY SECRETARY Non-Executive Director Mr Stefan Ross BBus (Acc) Company Secretary Experience and expertise Qualifications Stefan Ross has over 10 years of experience in accounting and secretarial services for ASX listed companies. His extensive experience includes ASX compliance, corporate governance control and implementation, statutory financial reporting, shareholder meeting requirements, capital raising management, and board and secretarial support. Stefan has a Bachelor of Business majoring in Accounting. Melanie Leydin – BBus (Acc. Corp Law) CA FGIA Joint Company Secretary (resigned on 29 October 2021) 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 from February 2000 to October 2021 was the principal of Leydin Freyer. In November 2021 Vistra acquired Leydin Freyer and, Melanie is now Vistra Australia's Managing Director. Vistra is a prominent provider of specialised consulting and administrative services to clients in the Fund, Corporate, Capital Markets, and Private Wealth sectors. Melanie has over 25 years’ experience in the accounting profession and over 15 years’ experience holding Board positions including Company Secretary of ASX listed entities. 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, initial public offerings, secondary raisings and shareholder relations. 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 B.Bus (Acc), Fellow of CPA Australia, Fellow of the Governance Institute of Australia. Experience and expertise Trevor has extensive experience in the development and operations of resource and construction projects within Australia and overseas performing as a director or senior executive in ASX listed or unlisted companies for over 30 years. Formerly, Trevor operated as an executive director for a gas production and storage project in Bass Strait; and as country director and manager for oil and gas exploration projects in Brunei. Trevor has also held senior roles in the development of oil and gas fields in the Timor Sea and consulted widely in South- East Asia. He has also been extensively involved in the development of significant resource projects including the Ballarat Gold Project where as CFO, he assisted the Company in its initial exploration programs and project development. Other current directorships None Former directorships (last 3 years) Experience and expertise None Interests in shares 264,753 ordinary fully paid shares Interests in options None Interests in rights None 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 '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. 25 MEETINGS OF DIRECTORS The number of meetings of the Company's Board of Directors ('the Board') held during the year ended 30 June 2022, and the number of meetings attended by each Director were: Mr N Newell Mr L De Maria Mr I Tchacos Mr T Slater Meetings Held Meetings Attended 5 5 5 3 5 5 5 3 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 Principles used to determine the nature and amount of remuneration Additionally, the reward framework should seek to enhance executives' interests by: 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: — 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. — competitiveness and reasonableness Non-executive Directors remuneration — 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 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. 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, annual leave, short term incentives and non-monetary benefits — share-based payments; and — other remuneration such as superannuation and long service leave The combination of these comprises the executive's total remuneration. 26 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 to Non- executive Directors (and employees) 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. There were no performance-based remuneration to the Executive Director during the year (2021: $50,000). Voting and comments made at the Company's 15 November 2021 Annual General Meeting ('AGM') The Company received 98.32% of 'for' votes in relation to its remuneration report for the year ended 30 June 2021. The Company did not receive any specific feedback at the AGM regarding its remuneration practices. Fixed remuneration, consisting of base salary, superannuation and non-monetary benefits, are reviewed annually by the Board, based on individual and business unit performance, the overall performance of the Company and comparable market remunerations. Executives can receive their fixed remuneration in the form of cash or other fringe benefits (for example motor vehicle benefits) where it does not create any additional costs to the Company and adds additional value to the executive. All Executives are eligible to receive a base salary (which is based on factors such as experience and comparable industry information) or consulting fee. The Board reviews the Executive Chairman's remuneration package, and the Executive Chairman reviews the senior Executives' remuneration packages annually by reference to the Consolidated Entity's performance, executive performance and comparable information within the industry. The chairman is not present at any discussions relating to determination of his/her own remuneration. 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 or performance rights 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. 27 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 key management personnel of the Consolidated Entity consisted of the following Directors of 3D Oil Limited: — Mr Noel Newell — Mr Ian Tchacos — Mr Leo De Maria — Mr Trevor Slater (appointed on 15 November 2021) Short-term benefits Short term incentives Post- employment benefits Long-term benefits Equity settled share based payments Bonus Super- annuation Long service leave Performance rights 2022 Non-Executive Directors: Mr I Tchacos Mr L De Maria Mr T Slater* Executive Directors: Mr N Newell 2021 Non-Executive Directors: Mr I Tchacos Mr L De Maria Executive Directors: Mr N Newell Salaries and fees $ 43,004 40,956 25,568 346,439 455,967 $ 43,151 41,096 $ - - - - - $ - - $ 4,296 4,091 2,557 23,100 34,044 $ 4,099 3,904 350,794 50,000 21,694 435,041 50,000 29,697 $ - - - 8,893 8,893 $ - - 6,752 6,752 $ 2,590 2,590 - - Total $ 49,890 47,637 28,125 378,432 5,180 504,084 $ $ 1,597 1,597 48,847 46,597 - 429,240 3,194 524,684 The proportion of remuneration linked to performance and the fixed proportion are as follows: Fixed remuneration At-risk short- term remuneration At-risk long term remuneration 2022 2021 2022 2021 2022 2021 94% 95% 100% 100% 97% 97% - 89% - - - - - - - 11% 6% 5% - - 3% 3% - - Name Non-Executive Directors: Mr I Tchacos Mr L De Maria Mr T Slater Executive Directors: Mr N Newell 28 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. (ii) The Company may terminate this employment agreement by providing 6 months written notice. (iii) The Company may terminate the contract at any time without notice if serious misconduct has occurred. Where termination with cause occurs, Mr Newell is only entitled to that portion of remuneration which is fixed, and only up to the date of termination. (iv) On termination of the agreement, Mr Newell will be entitled to be paid those outstanding amount owing to him up until the Termination date. Key management personnel have no entitlement to termination payments in the event of removal for misconduct. Share-based compensation Issue of shares There were no ordinary shares issued to directors and key management personnel as part of compensation during the year ended 30 June 2022 (2021: Nil). 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 2022 (2021: 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 2022 (2021: 225,806). 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 Mr Leo De Maria 112,903 112,903 17 November 2020 17 November 2022 17 November 2023 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. 29 Additional information The earnings of the Consolidated Entity for the five years to 30 June 2022 are summarised below: Other income including interest income Net loss before tax Net loss after tax 2022 $ 467 2021 $ 2020 $ 2019 $ 2018 $ 87,478 85,279 43,629 27,696 (1,147,179) (1,142,095) (3,006,065) (1,089,254) (1,154,810) (1,147,179) (1,142,095) (3,006,065) (1,089,254) (1,154,810) 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) 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 Mr T Slater * 2022 0.05 0.05 (0.43) 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) 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 - - - - - 189,769 - - 164,753 354,522 - - - 100,000 100,000 45,725,321 Balance at the end of the year 44,381,998 650,070 428,500 264,753 * Mr Trevor Slater was appointed as a Non- Performance rights holding Executive Director on 15 November 2021. The balance disclosed in the “Disposals/other” column represents his shareholding at the date of appointment. 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: Balance at the start of the year 112,903 112,903 225,806 Granted Vested Expired/ forfeited/ other Balance at the end of the year - - - - - - - - - 112,903 112,903 225,806 Performance rights over ordinary shares Mr L De Maria Mr I Tchacos This concludes the remuneration report, which has been audited. 30 Shares under option Shares under performance rights There were no unissued ordinary shares of 3D Oil Limited under option outstanding at the date of this report. 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 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 2022 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 2022. 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. Expiry date 17 November 2023 28 January 2024 29 January 2024 1 February 2024 Exercise price Number under rights $0.000 $0.000 $0.000 $0.000 225,806 80,645 80,645 56,451 443,547 Proceedings on behalf of the Company 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 30 September 2022 Melbourne 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. 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. 31 Grant Thornton Audit Pty Ltd Level 22 Tower 5 Collins Square 727 Collins Street Melbourne VIC 3008 GPO Box 4736 Melbourne VIC 3001 T +61 3 8320 2222 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 2022, 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, 30 September 2022 www.grantthornton.com.au ACN-130 913 594 Grant Thornton Audit Pty Ltd ACN 130 913 594 a subsidiary or related entity of Grant Thornton Australia Limited ABN 41 127 556 389 ACN 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 Limited 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 ACN 127 556 389 and its Australian subsidiaries and related entities. Liability limited by a scheme approved under Professional Standards Legislation. w 32 FINANCIAL REPORTS 33 CONSOLIDATED STATEMENT OF PROFIT OR LOSS AND OTHER COMPREHENSIVE INCOME For the year ended 30 June 2022 Other income Interest income Expenses Corporate expenses Employment expenses Occupancy expenses Depreciation and amortisation expense Exploration costs Share based payments Finance costs Loss before income tax expense Income tax expense Note 2022 5 $ - 467 Consolidated 2021 $ 82,908 4,570 (473,583) (451,925) 6 (505,620) (563,528) (14,449) (43,954) (121,275) (118,136) (15,994) (11,886) (4,839) (33,088) (9,072) (9,870) (1,147,179) (1,142,095) - - 6 14 6 7 Loss after income tax expense for the year attributable to the owners of 3D Oil Limited (1,147,179) (1,142,095) Other comprehensive income for the year, net of tax - - Total comprehensive income for the year attributable to the owners of 3D Oil Limited (1,147,179) (1,142,095) Basic earnings per share Diluted earnings per share 32 32 Cents (0.43) (0.43) Cents (0.43) (0.43) The above consolidated statement of profit or loss and other comprehensive income should be read in conjunction with the accompanying notes 34 CONSOLIDATED STATEMENT OF FINANCIAL POSITION As at 30 June 2022 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 2022 $ 2021 $ 8 9 10 11 12 13 14 15 20 16 20 17 1,243,195 3,048,802 29,992 93,577 - 31,752 93,577 41,924 1,366,764 3,216,055 17,542 257,109 47,212 16,525 79,156 76,641 6,207,257 5,374,599 6,529,120 5,546,921 7,895,884 8,762,976 925,255 820,345 75,488 96,614 228,444 231,912 1,229,187 1,148,871 190,555 1,916 192,471 - 4,585 4,585 1,421,658 1,153,456 6,474,226 7,609,520 18 55,483,678 55,483,678 17,559 9,072 (49,027,011) (47,883,230) 6,474,226 7,609,520 The above consolidated statement of financial position should be read in conjunction with the accompanying notes 35 CONSOLIDATED STATEMENT OF CHANGES IN EQUITY For the year ended 30 June 2022 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 Consolidated Balance at 1 July 2021 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: Lapse of performance rights Share-based payments Balance at 30 June 2022 Issued capital Accumulated losses $ $ 55,483,678 (46,741,135) (1,142,095) - (1,142,095) - - - - Reserves Total equity $ - - - - $ 8,742,543 (1,142,095) - (1,142,095) - 9,072 9,072 55,483,678 (47,883,230) 9,072 7,609,520 Issued capital Accumulated losses Reserves Total equity $ $ $ $ 55,483,678 (47,883,230) 9,072 7,609,520 - - - - - (1,147,179) - (1,147,179) - - - (1,147,179) - (1,147,179) 3,398 - (3,398) 11,885 - 11,885 55,483,678 (49,027,011) 17,559 6,474,226 The above consolidated statement of changes in equity should be read in conjunction with the accompanying notes 36 CONSOLIDATED STATEMENT OF CASH FLOWS For the year ended 30 June 2022 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 2022 $ 2021 $ (993,446) (1,132,676) 811 (4,839) 4,963 (9,870) (997,474) (1,137,583) - 88,908 Net cash used in operating activities 31 (997,474) (1,048,675) Cash flows from investing activities Payments for computer equipment Payments for intangibles Payments for exploration and evaluation Net cash used in investing activities Cash flows from financing activities Payment of principal element of lease liabilities Net cash used in financing activities Net decrease in cash and cash equivalents Cash and cash equivalents at the beginning of the financial year 11 13 (6,362) (6,862) - (30,001) (715,100) (851,721) (721,462) (888,584) (86,671) (91,130) (86,671) (91,130) (1,805,607) (2,028,389) 3,048,802 5,077,191 Cash and cash equivalents at the end of the financial year 8 1,243,195 3,048,802 The above consolidated statement of cash flows should be read in conjunction with the accompanying notes 37 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 30 June 2022 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 30 September 2022. 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. GOING CONCERN The financial report has been prepared on the going concern basis, which assumes continuity of normal business activities and 38 the realisation of assets and the settlement of liabilities in the ordinary course of business. The working capital position as at 30 June 2022 of the Consolidated Entity results in an excess of current assets over current liabilities of $137,577. The Consolidated Entity made a loss after tax of $1,147,179, incurred operating cash outflows of $997,474 and invested $715,100 in exploration and evaluation during the year. The cash balances, including term deposits, as at 30 June 2022 was $1,336,772. In addition, on 30 June 2022, the Company and ConocoPhillips Australia executed a Farm Out Agreement (“FOA”) in relation to the offshore Victorian Exploration Permit VIC/P79, located in the Otway Basin. Under the terms of the FOA, ConocoPhillips Australia will acquire an 80% interest in the Permit and operatorship in exchange for an upfront payment of USD$3 million (~AUD$4.35 million). ConocoPhillips Australia will also undertake to drill an exploration well as required by the Permit’s Primary Term minimum work commitment (currently required by February 2025). The Company will be carried for up to USD$35 million (~AUD$50.75 million) in well costs, above which it will contribute 20% of costs in line with its interest in the Permit. It should be noted that at the date of this report, the FOA is subject to conditions precedent, including the agreement and signing of a Joint Operating Agreement by both parties and required government / regulatory approvals. 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. The Consolidated Entity’s market capitalisation at 30 June 2022 is in excess of its net assets position of $6,474,226. As the Consolidated Entity is still in the exploration phase of activities, subject to necessary regulatory approvals, it has the ability to control the level of its operations and hence the level of its expenditure over the next 12 months. Should there be any delay in the funds from the VIC/P79 farmout, management are confident that they can reduce their level of expenditure in order to retain appropriate cash balances. Management remains very diligent in their ongoing monitoring of cash balances day by day. 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. The Directors are therefore confident that the going concern basis of preparation is appropriate as at the date of this report. ROUNDING OF AMOUNTS 3D Oil Limited is a type of Company that is referred to in ASIC Corporations (Rounding in Financial/Directors’ Reports) Instrument 2016/191 and therefore the amounts contained in this report and in the financial report have been rounded to the nearest dollar. BASIS OF PREPARATION These general purpose financial statements have been prepared in accordance with Australian Accounting Standards and Interpretations issued by the Australian Accounting Standards Board ('AASB') and the Corporations Act 2001, as appropriate for for-profit oriented entities. These financial statements also comply with International Financial Reporting Standards as issued by the International Accounting Standards Board ('IASB'). Historical cost convention The financial statements have been prepared under the historical cost convention, except for, where applicable, the revaluation of financial assets and liabilities at fair value through profit or loss, financial assets at fair value through other comprehensive income, investment properties, certain classes of property, plant and equipment and derivative financial instruments. 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. 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. Critical accounting estimates The preparation of the financial statements requires the use of certain critical accounting estimates. It also requires management to exercise its judgement in the process of applying the Consolidated Entity's accounting policies. The areas involving a higher degree of judgement or complexity, or areas where assumptions and estimates are significant to the financial statements, are disclosed in note 3. PARENT ENTITY INFORMATION In accordance with the Corporations Act 2001, these financial statements present the results of the Consolidated Entity only. Supplementary information about the parent entity is disclosed in note 27 . 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. PRINCIPLES OF CONSOLIDATION Other revenue The consolidated financial statements incorporate the assets and liabilities of all subsidiaries of 3D Oil Limited ('Company' or 'parent entity') as at 30 June 2022 and the results of all subsidiaries for the year then ended. 3D Oil Limited and its subsidiaries together are referred to in these financial statements as the 'Consolidated Entity'. Subsidiaries are all those entities over which the Consolidated Entity has control. The Consolidated Entity controls an entity when the Consolidated Entity is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power to direct the activities of the entity. Subsidiaries are fully consolidated from the date on which control is transferred to the Consolidated Entity. They are de-consolidated from the date that control ceases. Intercompany transactions, balances and unrealised gains on transactions between entities in the Consolidated Entity are eliminated. Unrealised losses are also eliminated unless the transaction provides evidence of the impairment of the asset transferred. Accounting policies of subsidiaries have been changed where necessary to ensure consistency with the policies adopted by the Consolidated Entity. The acquisition of subsidiaries is accounted for using the acquisition method of accounting. A change in ownership interest, without the loss of control, is accounted for as an equity transaction, where the difference between the consideration transferred and the book value of the share of the non-controlling interest acquired is recognised directly in equity attributable to the parent. Where the Consolidated Entity loses control over a subsidiary, it derecognises the assets including goodwill, liabilities and 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 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 39 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. 40 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. At inception or on reassessment of a contract that contains a lease component, the Consolidated Entity allocates the consideration in the contract to each lease component on the basis of their relative stand-alone prices. However, for the leases of land and buildings in which it is a lessee, the Consolidated Entity has elected not to separate non-lease components and account for the lease and non-lease components as a single lease component. As a lessee The Consolidated Entity recognises a right- of-use asset and a lease liability at the lease commencement date. The right-of-use asset is initially measured at cost, which comprises the initial amount of the lease liability adjusted for any lease payments made at or before the commencement date, plus any initial direct costs incurred and an estimate of costs to dismantle and remove the underlying asset or to restore the underlying asset or the site on which it is located, less any lease incentives received. The right-of-use asset is subsequently depreciated using the straight-line method from the commencement date to the earlier of the end of the useful life of the right-of- use asset or the end of the lease term. The estimated useful lives of right-of-use assets are determined on the same basis as those of property and equipment. In addition, the right-of-use asset is periodically reduced by impairment losses, if any, and adjusted for certain remeasurements of the lease liability. The lease liability is initially measured at the present value of the lease payments that are not paid at the commencement date, discounted using the interest rate implicit in the lease or, if that rate cannot be readily determined, the Consolidated Entity’s incremental borrowing rate. Generally, the Consolidated Entity uses its incremental borrowing rate as the discount rate. Lease payments included in the measurement of the lease liability comprise the following: — Fixed payments, including in-substance fixed payments; — Variable lease payments that depend on an index or a rate, initially measured using the index or rate as at the commencement date; — Amounts expected to be payable under a residual value guarantee; and — The exercise price under a purchase option that the Consolidated Entity is reasonably certain to exercise, lease payments in an optional renewal period if the Consolidated Entity is reasonably certain to exercise an extension option, and penalties for early termination of a lease unless the Consolidated Entity is reasonably certain not to terminate early. The lease liability is measured at amortised cost using the effective interest method, It is remeasured when there is a change in future lease payments arising from a change in an index or rate, if there is a change in the Consolidated Entity’s estimate of the amount expected to be payable under a residual value guarantee, or if the Consolidated Entity changes its assessment of whether it will exercise a purchase, extension or termination option. When the lease liability is remeasured in this way, a corresponding adjustment is made to the carrying amount of the right- of-use assets, or is recorded in profit or loss if the carrying amount of the right-of-use asset has been reduced to zero. Short-term leases and leases of low-value assets The Consolidated Entity has elected not to recognise right-of-use assets and lease liabilities for short-term leases that have a lease term of 12 months or less and leases of low-value assets, including IT equipment. The Consolidated Entity recognises the lease payments associated with these leases as an expense on a straight-line basis over the lease term. GOODS AND SERVICES TAX ('GST') AND OTHER SIMILAR TAXES Revenues, expenses and assets are recognised net of the amount of associated GST, unless the GST incurred is not recoverable from the tax authority. In this case it is recognised as part of the cost of the acquisition of the asset or as part of the expense. Receivables and payables are stated inclusive of the amount of GST receivable or payable. The net amount of GST recoverable from, or payable to, the tax authority is included in other receivables or other payables in the statement of financial position. Cash flows are presented on a gross basis. The GST components of cash flows arising from investing or financing activities which are recoverable from, or payable to the tax authority, are presented as operating cash flows. Commitments and contingencies are disclosed net of the amount of GST recoverable from, or payable to, the tax authority. FAIR VALUE MEASUREMENT When an asset or liability, financial or non-financial, is measured at fair value for recognition or disclosure purposes, the fair value is based on the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date; and assumes that the transaction will take place either: in the principal market; or in the absence of a principal market, in the most advantageous market. Fair value is measured using the assumptions that market participants would use when pricing the asset or liability, assuming they act in their economic best interests. For non-financial assets, the fair value measurement is based on its highest and best use. Valuation techniques that are appropriate in the circumstances and for which sufficient data are available to measure fair value, are used, maximising the use of relevant observable inputs and minimising the use of unobservable inputs. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS NOT YET MANDATORY OR EARLY ADOPTED Australian Accounting Standards and Interpretations that have recently been issued or amended but are not yet mandatory, have not been early adopted by the Consolidated Entity for the annual reporting period ended 30 June 2022. 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. 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 either 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. 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. 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. 41 NOTE 4. OPERATING SEGMENTS 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. 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. 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. 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 Total employment costs Finance costs Consolidated 2021 $ 82,908 2022 $ - Consolidated 2022 $ 2021 $ (5,355) (4,368) (86,491) (86,340) (91,846) (90,708) (29,429) (27,428) (121,275) (118,136) (37,498) (26,306) (468,122) (537,222) (505,620) (563,528) Interest and finance charges paid/payable on lease liabilities (4,839) (9,870) 42 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 25% (2021: 26%) Tax effect amounts which are not deductible/(taxable) in calculating taxable income: Entertainment expenses Share-based payments Prior year under/over adjustment Change in unrecognised temporary differences Amounts not brought to account as deferred tax assets 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, T49P 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. The Company has not recognised a deferred tax asset with respect to the carried forward un-deducted expenditure. 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 2022 $ 2021 $ (1,147,179) (1,142,095) (286,795) (296,945) 349 2,972 (234,022) (195,629) 949 2,359 60,223 7,145 713,125 (226,269) - - Consolidated 2022 $ 2021 $ 15,960,358 15,247,233 15,960,358 15,247,233 43 NOTE 8. CURRENT ASSETS – CASH AND CASH EQUIVALENTS Consolidated 2022 $ 2021 $ 1,243,195 3,048,802 Consolidated 2022 $ 2021 $ 18,024 23,659 129 11,839 472 7,621 29,992 31,752 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. NOTE 9. CURRENT ASSETS – OTHER RECEIVABLES 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 other receivables 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 an original term to maturity greater than 3 months. One of these cash deposits is pledged as a security for the lease arrangement for office space. Consolidated 2022 $ 2021 $ 93,577 93,577 44 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 2020 Additions Depreciation expense Balance at 30 June 2021 Additions Depreciation expense Balance at 30 June 2022 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. Consolidated 2022 $ 2021 $ 184,083 184,083 (184,083) (184,083) - - 32,080 (14,538) 17,542 25,708 (9,183) 16,525 17,542 16,525 Computer equipment $ 14,031 6,862 (4,368) 16,525 6,372 (5,355) Total $ 14,031 6,862 (4,368) 16,525 6,372 (5,355) 17,542 17,542 45 NOTE 12. NON-CURRENT ASSETS – RIGHT-OF-USE ASSETS The Consolidated Entity has a lease arrangement for office space. In June 2022, the lease was renewed for a three-year period 1 June 2022 to 31 May 2025 with no further option to extend. 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 2022 $ 2021 $ 516,286 251,842 (259,177) (172,686) 257,109 79,156 Office space – right-of-use $ 165,496 (86,340) 79,156 264,444 (86,491) Total $ 165,496 (86,340) 79,156 264,444 (86,491) 257,109 257,109 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 2022. 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 2020 Depreciation expense Balance at 30 June 2021 Additions Depreciation expense Balance at 30 June 2022 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. 46 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. 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 2020 Additions Amortisation expense Balance at 30 June 2021 Amortisation expense Balance at 30 June 2022 Accounting policy for intangible assets 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. 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. Consolidated 2022 $ 2021 $ 364,791 364,791 (317,579) (288,150) 47,212 76,641 Software $ 74,068 30,001 Total $ 74,068 30,001 (27,428) (27,428) 76,641 76,641 (29,429) (29,429) 47,212 47,212 47 NOTE 14. NON-CURRENT ASSETS – EXPLORATION AND EVALUATION Exploration and evaluation expenditure Reconciliations Reconciliations of the written down values at the beginning and end of the current and previous financial year are set out below: Consolidated 2022 $ 2021 $ 6,207,257 5,374,599 Area of interest T49P Area of interest VIC/P74 Area of interest WA-527-P Area of interest VIC/P79 Consolidated Balance at 1 July 2020 Additions Balance at 30 June 2021 Additions $ $ $ 3,592,827 424,751 4,017,578 342,452 185,709 339,241 524,950 38,309 768,001 64,070 832,071 327,418 Total $ 4,546,537 828,062 5,374,599 $ - - - 124,479 832,658 Balance at 30 June 2022 4,360,030 563,259 1,159,489 124,479 6,207,257 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, WA-527-P in Western Australia and VIC/P79, an offshore exploration permit in the Otway Basin. 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. The Consolidated Entity has carried out an impairment review of the carrying amount of its exploration expenditure in relation to VIC/P74, T/49P, WA-527-P and VIC/P79 following the end of the financial year as at 30 June 2022. Based on the review no impairments were identified in relation to these tenements. Farm-out in the exploration and e valuation phase Accounting policy for exploration and evaluation assets 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 29 for further information on the Consolidated Entity’s farm-out arrangements. 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 The Consolidated Entity expensed exploration costs of $15,994 (2021: $33,088) related to VIC/P57 Exploration Permit (which was surrendered subsequent to the financial year) in the statement of profit or loss and other comprehensive income in the year ended 30 June 2022. 48 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. NOTE 16. CURRENT LIABILITIES – EMPLOYEE BENEFITS Annual leave Long service leave Employee benefits Amounts not expected to be settled within the next 12 months The current provision for long service leave includes all unconditional entitlements where employees have completed the required period of service and also those where employees are entitled to pro-rata payments in certain circumstances. The entire amount is presented as current, since the company does not have an unconditional right to defer settlement. Accounting policy for employee benefits Short-term employee benefits Liabilities for wages and salaries, including non-monetary benefits, annual leave, long service leave and accumulating sick 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. Non-accumulating sick leave is expensed to profit or loss when incurred. Consolidated 2021 $ 54,467 695,894 69,984 2022 $ 119,505 695,894 109,856 925,255 820,345 Consolidated 2022 $ 2021 $ 69,769 58,076 134,591 136,956 24,084 36,880 228,444 231,912 49 NOTE 17. NON-CURRENT LIABILITIES – EMPLOYEE BENEFITS Long service leave Consolidated 2022 $ 2021 $ 1,916 4,585 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 2022 Shares 2021 Shares Consolidated 2022 $ 2021 $ Ordinary shares – fully paid 265,188,372 265,188,372 55,483,678 55,483,678 Ordinary shares Capital risk management 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. 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 2021 Annual Report. Accounting policy for issued capital Ordinary shares are classified as equity. Incremental costs directly attributable to the issue of new shares or options are shown in equity as a deduction, net of tax, from the proceeds. NOTE 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. 50 NOTE 20. LEASE LIABILITIES Lease liabilities Current lease liabilities Non-current lease liabilities Total lease liabilities 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 2022, the Consolidated Entity incurred interest charges of $4,839, as disclosed in note 6. Lease liability outflows Lease liability related cash outflows are disclosed in the statement of cashflows. 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. Consolidated 2022 $ 2021 $ 75,488 190,555 96,614 - 266,043 96,614 Consolidated 2022 $ 2021 $ 257,109 79,156 Consolidated 2022 92,045 203,591 2021 96,614 - 295,636 96,614 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. 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. 51 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 2022 was $0.6878 (30 June 2021: $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. 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. Interest rate risk LIQUIDITY RISK The Consolidated Entity's only exposure to interest rate risk is in relation to deposits held. Deposits are held with reputable banking financial institutions. The tables below illustrate the impact on profit before tax based upon expected volatility of interest rates using market data and analysis forecasts. 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. Consolidated – 2022 Non-derivatives Non-interest bearing Trade and other payables Interest-bearing – fixed rate Lease liability Total non-derivatives Consolidated – 2021 Non-derivatives Non-interest bearing Trade and other payables Interest-bearing – fixed rate Lease liability Total non-derivatives Weighted average interest rate % - 1 year or less $ 925,255 7.50% 92,045 % - 7.50% 1,017,300 $ 820,345 96,614 916,959 Between 1 and 2 years Between 2 and 5 years Over 5 years $ - $ - 104,397 104,397 99,194 99,194 $ - - - $ - - - $ - - - $ - - - Remaining contractual maturities $ 925,255 295,636 1,220,891 $ 820,345 96,614 916,959 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. 52 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 Mr Trevor Slater Executive Chairman Non-Executive Director Non-Executive Director Non-Executive Director (appointed on 15 November 2021) 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 Share-based payments 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 Audit or review of the financial statements NOTE 24. CONTINGENT LIABILITIES The Consolidated Entity provided a security deposit of $48,827 (2021: $48,827). The Consolidated Entity will forgo this deposit if conditions of return are not met. With the exception to the above matter, the Consolidated Entity does not have any other contingent liabilities at reporting date. Consolidated 2022 $ 2021 $ 455,967 485,041 34,044 29,697 8,893 5,180 6,752 3,194 504,084 524,684 Consolidated 2022 $ 2021 $ 58,500 55,000 53 NOTE 25. COMMITMENTS Exploration Licenses – Commitments for Expenditure Committed at the reporting date but not recognised as liabilities, payable: Within one year Two to five years WA-527-P, the current indicative expenditure commitment for Years 5-6 is currently gross $30.8 million and this would be occurring in 2022-2025 years. T49P The Consolidated Entity holds 20% interest in the T/49P Exploration Permit and ConocoPhillips Australia SH1 Pty Ltd holds 80% interest in the Permit and is Operator on behalf of the Joint Operation. The commitments above do 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, as per Joint Operating Agreement. Under the terms of Joint Operating Agreement, the Company 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. On 16 March 2021, NOPTA issued a variation notice to the Exploration Permit T/49P, as a result of which seismic acquisition and drill planning works in Year 5 and the drilling of an exploration well in Year 6 have been deferred to the year ended 21 August 2023 and 21 August 2024, respectively. VIC/P79 The Company holds 100% interest in the VIC/P79 Exploration Permit which was granted in 2020. On 30 June 2022, the Company executed a Farmout Agreement with ConocoPhillips Australia SH2 Pty Ltd in relation to the VIC/P79 Exploration Permit. Under the terms of the agreement, ConocoPhillips Australia will acquire an 80% interest in the Exploration Permit and will become the Operator on behalf of the Joint Operation. At the date of this report, agreement is subject to conditions precedent, including the agreement and signing of a Joint Operating Agreement by both parties and required government/ regulatory approvals. 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. VIC/P74 On 8 October 2020, NOPTA approved Hibiscus Petroleum Berhad to enter into an agreement for a Joint Operations with the Company for the offshore Gippsland Basin Exploration Permit VIC/P74. The Company remained as the operator with 50% equity. In July 2022, Hibiscus Petroleum have decided to transfer their 50% participating interest back to the Company and applied for a Transfer of Title which is currently under review with NOPTA. Accordingly, the Company has included in the above commitments its share of indicative expenditure relating to VIC/P74 for year 4 at 100% (2021: 50%). 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 5 in relation to VIC/P74, the current indicative expenditure commitment for Years 5-6 is currently gross $40.6 million, and this would be occurring in 2023-2025 years. WA-527-P The Company holds 100% interest in the WA-527-P Exploration Permit, which covers 6,500km2 of the offshore Bedout Sub-basin. The Company has included its commitments for indicative expenditure in the 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 54 Consolidated 2022 $ 2021 $ 4,660,000 3,060,000 80,000 - 4,740,000 3,060,000 Year one (1) to three (3) commitments for VIC/P79 Exploration Permit is $900,000 in total for seismic data acquisition and geological and geophysical studies. The above commitment note include 20% of year one (1) to three (3) commitment, which the Company expects to contribute in line with its interest in the Exploration Permit. The commitments above do not include Drill Exploration Well commitment, as they are expected to be covered by the farm-in partner, ConocoPhillips Australia Pty Ltd, upon signing of a Joint Operating Agreement. It is expected that the ConocoPhillips Australia will also undertake to drill an exploration well as required by the Permit’s Primary Term minimum work commitment (currently required by February 2025). The Company will be carried for up to USD$35 million (~AUD$50.751 million) in well costs, above which it will contribute 20% of costs in line with its interest in the Exploration Permit. 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/P79, the current indicative expenditure commitment for Years 4-6 is currently gross $12.8 million and this would be occurring in 2025-2028 years. VIC/P57 The Company held 24.9% interest in the VIC/P57 Exploration Permit with remaining equity held by Joint Operation partner and operator, Hibiscus Petroleum. During the year, the Joint Operation has submitted a ‘Consent to Surrender Title’ application ahead of the Year 4 work program, which was accepted by NOPTA subsequent to the end of financial year. Therefore, the commitments note above do not include commitments for indicative expenditure relating to Exploration Permit VIC/P57. NOTE 26. RELATED PARTY TRANSACTIONS Parent entity Key management personnel 3D Oil Limited is the parent entity. Subsidiaries Interests in subsidiaries are set out in note 28. Disclosures relating to key management personnel are set out in note 22 and the remuneration report included in the Directors' report. 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. Joint operations Transactions with related parties Loans to/from related parties Interests in joint operations are set out in note 29. There were no transactions with related parties during the current and previous financial year. There were no loans to or from related parties at the current and previous reporting date. NOTE 27. 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 2022 $ Parent 2021 $ (1,147,188) (1,142,047) (1,147,188) (1,142,047) 2022 $ Parent 2021 $ 1,274,029 3,123,331 5,144,732 5,976,850 1,229,187 1,113,888 1,421,658 1,118,473 55,483,678 55,483,678 17,559 9,072 (51,778,163) (50,634,373) 3,723,074 4,858,377 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 2022 and 30 June 2021. Contingent liabilities The parent entity had no contingent liabilities as at 30 June 2022 and 30 June 2021. Capital commitments – Property, plant and equipment The parent entity had no capital commitments for property, plant and equipment as at 30 June 2022 and 30 June 2021. 55 Significant accounting policies The accounting policies of the parent entity are consistent with those of the Consolidated Entity, as disclosed in note 2, except for the following: — Investments in subsidiaries are accounted for at cost, less any impairment, in the parent entity. — Investments in associates are accounted for at cost, less any impairment, in the parent entity. — Dividends received from subsidiaries are recognised as other income by the parent entity and its receipt may be an indicator of an impairment of the investment. — Significant estimates and judgement – recoverability of loan to subsidiary. No objective indicators of impairment as the current best estimates of potential resources indicate a quantity of oil/gas that would allow recovery of the amount due in full. Ownership interest 2022 % 2021 % 100.00% 100.00% Ownership interest 2022 % 20.00% 50.00% 24.90% 100.00% 2021 % 20.00% 50.00% 24.90% - NOTE 28. 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 29. 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 VIC/P74, Gippsland Basin, offshore Victoria Australia Australia VIC/P57, Gippsland Basin, offshore Victoria* Australia VIC/P79, Otway Basin, offshore Victoria** Australia * The Company held 24.9% interest in the VIC/P57 Exploration Permit with remaining equity held by joint venture partner and operator, Hibiscus Petroleum. During the financial year, the Joint Venture has submitted a ‘Consent to Surrender Title’ application ahead of the Year 4 work program with NOPTA, which was accepted by NOPTA subsequent to the end of financial year. ** On 4 February 2022, the Consolidated Entity announced that the NOPTA had awarded the Consolidated Entity the VIC/P79 exploration permit in the offshore Otway Basin. On 30 June 2022, the Consolidated Entity announced that ConocoPhillips Australia SH2 Pty Ltd and the Company have executed a Farmout Agreement in relation to the offshore Victorian Exploration Permit VIC/P79 (“Permit”), located in the Otway Basin. Under the terms of the FOA, ConocoPhillips Australia will acquire an 80% interest in the Permit and operatorship. 56 NOTE 30. EVENTS AFTER THE REPORTING PERIOD On 2 September 2022, the Consolidated Entity announced that the South Australia Department of Energy and Mining has awarded the Company the GSEL 759 Gas Storage Exploration Licence in onshore Otway Basin. The licence covers an area of 1.02km2, centrally located around the plugged and abandoned Caroline-1 wellhead, over part of the now depleted Caroline Field, originally used for the production of carbon dioxide in the Otway Basin. The Field is potentially suitable for the storage of hydrogen, natural gas, or carbon dioxide. The acquisition of GSEL 759 represents an exciting development opportunity for the Company in broadening 3D Oil’s strategy in the rapidly changing East Coast energy market. No other matter or circumstance has arisen since 30 June 2022 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 31. RECONCILIATION OF LOSS AFTER INCOME TAX TO NET CASH USED IN OPERATING ACTIVITIES Loss after income tax expense for the year Adjustments for: Depreciation, amortisation net of other non-cash lease adjustments Share-based payments Change in operating assets and liabilities: Decrease/(increase) in other receivables Decrease/(increase) in prepayments Decrease in trade and other payables Increase in employee benefits Net cash used in operating activities Consolidated 2022 $ 2021 $ (1,147,179) (1,142,095) 112,920 118,136 11,886 9,072 (3,875) 41,924 123 (2,477) (19,808) (113,832) 6,658 82,398 (997,474) (1,048,675) 57 NOTE 32. LOSS PER SHARE Loss after income tax attributable to the owners of 3D Oil Limited (1,147,179) (1,142,095) 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 Consolidated 2022 $ 2021 $ Cents (0.43) (0.43) Cents (0.43) (0.43) Basic earnings per share Diluted earnings per share Accounting policy for earnings loss per share Diluted 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 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 33. 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. 58 2022 Grant date Expiry date Exercise price 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 $0.000 $0.000 $0.000 $0.000 $0.000 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: Balance at the start of the year 225,806 80,645 80,645 112,903 241,935 741,934 Granted Exercised - - - - - - - - - - - - Expired/ forfeited/ other - - - (56,452) (241,935) (298,387) Balance at the end of the year 225,806 80,645 80,645 56,451 - 443,547 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 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 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. The weighted average remaining contractual life of performance rights at 30 June 2021 is 1.62 years. 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. 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. 59 DIRECTORS' DECLARATION 30 June 2022 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 2022 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 30 September 2022 Melbourne 60 Grant Thornton Audit Pty Ltd Level 22 Tower 5 Collins Square 727 Collins Street Melbourne VIC 3008 GPO Box 4736 Melbourne VIC 3001 T +61 3 8320 2222 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 subsidiaries (the Group), which comprises the consolidated statement of financial position as at 30 June 2022, 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 consolidated financial statements, including a summary of significant accounting policies, and the Directors’ declaration. In our opinion, the accompanying financial report of the Group is in accordance with the Corporations Act 2001, including: a giving a true and fair view of the Group’s financial position as at 30 June 2022 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 Group 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 (including Independence Standards) (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. Material uncertainty related to going concern We draw attention to Note 2 in the financial statements, which indicates that the Group incurred a net loss of $1,147,179 during the year ended 30 June 2022, and as of that date, the Group’s current assets exceeded its current liabilities by $137,577. As stated in Note 2, these events or conditions, along with other matters as set forth in Note 2 , indicate that a material uncertainty exists that may cast doubt on the Group’s ability to continue as a going concern. Our opinion is not modified in respect of this matter. www.grantthornton.com.au ACN-130 913 594 Grant Thornton Audit Pty Ltd ACN 130 913 594 a subsidiary or related entity of Grant Thornton Australia Limited ABN 41 127 556 389 ACN 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 Limited 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 ACN 127 556 389 and its Australian subsidiaries and related entities. Liability limited by a scheme approved under Professional Standards Legislation. w 61 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. In addition to the matter described in the Material uncertainty related to going concern section, we have determined the matters described below to be the key audit matters to be communicated in our report. 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 the Group are in the exploration stage, exploration expenditure is capitalised in accordance with Australian Accounting Standard AASB 6 Exploration for and Evaluation of Mineral Resources. The Group 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. 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 obtain documentation to support the amount capitalised in line with AASB 6; • evaluating management's assessment of impairment indicators for the capitalised exploration assets under AASB 6 by: AASB 6 requires exploration and evaluation asset to be assessed for impairment when facts and circumstances suggest that the carrying amount of an exploration and evaluation asset may exceed its recoverable amount. AASB 6 provides a list of four indicators, however that list is not exhaustive and therefore subjectivity is involved in the assessment. 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. − assessing the right to explore the areas of interest has not expired or will not expire in the near future without an expectation of renewal; − making enquires management regarding their intentions to carry out exploration and evaluation activity in the relevant exploration area, including review of managements’ budgeted expenditure; − 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; − considering any other available evidence of impairment; • assessing management's consequent determination of impairment loss (if any); 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 Group’s annual report for the year ended 30 June 2022, 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. Grant Thornton Australia Limited (cid:3) 62 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 Group’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 Group 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 at: 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 27 to 31 of the Directors’ report for the year ended 30 June 2022. In our opinion, the Remuneration Report of 3D Oil Limited, for the year ended 30 June 2022 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, 30 September 2022 Grant Thornton Australia Limited (cid:3) 63 SHAREHOLDER INFORMATION 30 June 2022 The shareholder information set out below was applicable as at 12 September 2022. DISTRIBUTION OF EQUITABLE SECURITIES Analysis of number of equitable security holders by size of holding: Ordinary shares Number of holders Ordinary shares % of total shares issued total shares issued % performance rights Number of performance rights Number of performance holders 1 to 1,000 1,001 to 5,000 5,001 to 10,000 10,001 to 100,000 100,001 and over 51 116 130 462 254 0.01 0.15 0.42 7.16 15,355 390,080 1,120,183 18,991,830 92.26 244,670,924 - - - - - - 49.09 50.91 217,741 225,806 1,013 100.00 265,188,372 100.00 443,547 Holding less than a marketable parcel 239 0.36 945,618 - - - - - 3.00 2.00 5.00 - 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 (Newell Family A/C) Oceania Hibiscus SDN BHD\C Mr John Philip Daniels Bill Hopper Citicorp Nominees Pty Limited Sanlirra Pty Ltd (Sanlirra Super Fund A/C) BNP Paribas Noms Pty Ltd (DRP) HSBC Custody Nominees (Australia) Limited Northern Business Planning Centre Pty Ltd (Newell Super A/C) Mr Tai Tran HSBC Custody Nominees (Australia) Limited – A/C 2 Blamnco Trading Pty Ltd Pengold Pty Ltd (Pengold Super Fund A/C) Vin Naidu + Wendy Naidu Mr Richard John Loveridge + Mrs Katrina Loveridge (Rj Loveridge S/Fund A/C) Mr Giovanni Monteleone + Mrs Frances Monteleone Mr Russell Barwick Eilie Sunshine Pty Ltd (Eilie Sunshine Superfund A/C) Mr Michael Andrew Jaket Mr Peter Alaric Hayes 64 Number held 38,604,620 30,963,000 7,557,500 6,475,000 5,710,094 5,000,000 4,840,950 4,691,161 4,675,385 4,500,000 4,322,940 4,000,000 3,714,000 2,837,500 2,771,419 2,550,000 2,500,000 2,500,000 2,250,000 2,237,000 Ordinary shares % of total shares issued 14.56 11.68 2.85 2.44 2.15 1.89 1.83 1.77 1.76 1.70 1.63 1.51 1.40 1.07 1.05 0.96 0.94 0.94 0.85 0.84 142,700,569 53.82 Number on issue 443,547 Number of holders 5 Ordinary shares % of total shares issued 16.66 11.68 Number held 44,192,229 30,963,000 CORPORATE GOVERNANCE STATEMENT The Company’s 2022 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 Thursday, 10 November 2022. 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 (AEDT) on 29 September 2022. 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 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. PETROLEUM TENEMENT HOLDINGS Tenement and Location VIC/P79 Offshore Otway Basin, VIC1 & 2 T/49P Offshore Otway Basin, TAS WA-527-P Offshore Roebuck Basin, WA VIC/P57 Offshore Gippsland Basin, VIC3 VIC/P74 Offshore Gippsland Basin, VIC4 GSEL759 Otway Basin, SA5 1 On 4 February 2022, 3D Oil Limited announced the award of VIC/P79 100% to TDO. 2 On 1 July 2022, 3D Oil Limited announced the farmout of 80% interest in VIC/P79 and operatorship. 3 In February 2022, 3D Oil Limited applied to NOPTA to relinquish its participating interest in VIC/P57. 4 In July 2022, the Joint Venture applied to NOPTA to transfer 50% interest from Carnarvon Hibiscus to 3D Oil Limited. 5 On 2 September 2022, 3D Oil Limited announced the award of GSEL gas storage exploration licence in the onshore Otway Basin in South Australia. Beneficial interest % 100.00% 20.00% 100.00% 24.90% 50.00% 100.00% 65 CORPORATE DIRECTORY Directors Noel Newell (Executive Chairman) Ian Tchacos (Non-Executive Director) Leo De Maria (Non-Executive Director) Trevor Slater (Non-Executive Director) Auditor Grant Thornton Audit Pty Ltd Collins Square Tower 5 727 Collins Street Melbourne, Victoria 3008 Stock exchange listing 3D Oil Limited securities are listed on the Australian Securities Exchange (ASX Code: TDO) Website 3doil.com.au Company secretary 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 66 ANNUAL REPORT 2022
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