Vintage Energy Limited
Annual Report 2020

Plain-text annual report

Annual Report 2020 1 Vintage Energy Ltd Annual Report 2020Competent persons statement The hydrocarbon resource estimates in this report have been compiled by Neil Gibbins, Managing Director, Vintage Energy Ltd. Mr Gibbins has over 35 years of experience in petroleum geology and is a member of the Society of Petroleum Engineers. Mr Gibbins consents to the inclusion of the information in this report relating to hydrocarbon Contingent and Prospective Resources in the form and context in which it appears. The Contingent and Prospective Resource estimates contained in this report are in accordance with the standard definitions set out by the Society of Petroleum Engineers, Petroleum Resource Management System. 2 Contents 4 8 A message from the Chairman and Managing Director Review of Operations 20 Reserves and Resources Statement 24 Directors’ Report 36 Auditor’s Independence Declaration 37 Corporate Governance Statement 38 Statement of Profit or Loss and Other Comprehensive Income 39 Statement of Financial Position 40 Statement of Changes in Equity 41 Statement of Cash Flows 42 Notes to the Financial Statements 63 Directors’ Declaration 64 Independent Auditor’s Report 67 Information Pursuant to the Listing requirement of the ASX 69 Glossary 74 Corporate Directory 3 Vintage Energy Ltd Annual Report 2020A message from the Chairman and Managing Director and information provided by the Federal, South Australian and Queensland Governments. These actions ensured the safety and well-being of our employees and contractors, as well as supported the long-term viability of the business. We are thankful to all of our stakeholders who have supported us during this busy and rewarding year. Included on this list are the contractors working on-site, our joint venture parties, the State government support with cross-border logistics, as well as our industry bodies, APPEA and SACOME, who assisted with approvals that allowed us to proceed in the current restrictive COVID environment. Even though a lot of other companies delayed programs, we delivered a safe, high impact project with Vali-1 ST1 that we believe will soon be generating sustainable returns to our shareholders. A special mention goes to our team at Vintage. While we often talk about the talent we have within our organisation, it is truly when discoveries like Vali-1 ST1 and Nangwarry-1 are made that this talent is on full display. Our team has great experience and maturity, but Vintage Energy is still young as a listed company. Nevertheless, it is the depth of knowledge that saw the Vintage team deliver our two discoveries during the last, most challenging, financial year. One of these is our first gas discovery as an operator. What makes this operated discovery all the more special is that it is in a familiar setting, the Cooper Basin, where we have had much success in our ‘past lives’. Also pleasing was the efficient and safe completion of all the wells in which we participated. Reg Nelson, Chairman (left) and Neil Gibbins, Managing Director (right) What a year it has been for Vintage Energy Ltd. Challenging on many levels, with the outbreak of COVID-19, but also very rewarding, with the team at Vintage delivering on both operational and corporate fronts. We drilled four wells, fracture stimulated one well, completed two farm-ins and also won a gazettal bid which further grew our footprint in the Cooper Basin. Corporately, we were successful with an oversubscribed capital raising in the latter part of the financial year, which was completed under the dark cloud of COVID-19. COVID-19 has impacted everyone’s lives in some way shape or form, and we only hope that you, your families and loved ones are staying safe and taking the necessary precautionary measures to help to keep this virus contained. The Board and management acted expeditiously in response to COVID-19 and worked within the guidelines 4 Safety will always be our number one priority as we pursue our quest for gas and oil discoveries to supply markets very much in need of these vital commodities. We have more than delivered on the promises made when we listed on the ASX just over two years ago. We raised $30 million to build a portfolio of quality assets for oil and gas exploration and appraisal. We not only achieved this objective, but then delivered two discoveries in quick time. To complete the stimulation and testing of the Vali-1 ST1 discovery, we raised $3 million through a share placement and SPP in April and May. Due to the COVID-19 pandemic, which drove the exceptional crash in the oil price and financial markets more generally, we decided to only raise the minimum amount of capital to allow us to prove-up the Vali-1 ST1 discovery. By doing this we sought to minimise the dilutionary impact that could have resulted from a larger capital raising with a share price close to all-time lows. As many of you are aware, these funds were put to very good use with the successful and safe completion of the six-stage fracture stimulation of the Vali-1 ST1 well and subsequent flow test. The flow test realised a choked back stabilised raw gas rate of 4.3 MMscfd (through a 36/64” choke at 942 psi) over a two day period. Transient tests were also undertaken with rates between 3.7 MMscfd (through a 24/64” choke at 1,676 psi) and 7.5 MMscfd (through a 32/64” choke at 1,593 psi). The flow test vindicated our belief in the Southern Flank of the Cooper Basin as an area that still holds a lot of potential. The trick is knowing where to drill! We have now declared Vali a commercial field and are instigating the process of connecting it via pipeline to the main trunkline that feeds into the Moomba gas processing facility. We expect a gas sales agreement will soon be completed. Once done, it will trigger the first significant milestone for Vintage and one of our key strategic imperatives identified from the outset – delivering gas into the east coast Australian domestic market. With first gas production comes cash flow, and to this end we are confident we will be generating revenue in the first half of next calendar year. We hope you share our excitement and enthusiasm for what is an outstanding achievement for such a young company. And it is not just the Vali gas field that has piqued the interest of the observant investor, but the number of other leads and prospects around Vali, including the Odin prospect, which will soon be targeted. In order to execute on our broader Cooper Basin program, we have embarked on a further capital raising. The funds targeted will be used to connect Vali-1 ST1 to the Moomba gathering system, drill two further wells in the Vali Field, drill the Odin prospect, test the Nangwarry carbon dioxide (“CO2”) discovery, cover the cost of long lead items for the drilling of the Cervantes oil prospect in the Perth Basin, fund GG&E desktop work and be used for working capital. Once these funds are secured, Vintage will have optionality regarding alternate financing arrangements into the future. The last financial year was focused on building our Cooper Basin portfolio, delivering permits that play to our strengths, with geology that we are familiar with and from which we have generated much success over time. To this end we farmed-in to ATP 2021, which has already proven a very prospective permit, with 25 oil and gas leads and prospects initially identified, and the adjacent PRL 211 permit. We are the operator for both of these permits, and as such will be working with our joint venture parties to undertake further drilling, which will include the Odin prospect targeted for Q3 FY21. In June 2020 we announced the success of our bid for gazettal Block CO2019-E (PELA 679), located in the south west of the Cooper Basin, in South Australia. Vintage Energy Ltd Annual Report 2020 55 Vintage Energy Ltd Annual Report 2020A message from the Chairman and Managing Director continued... We secured an initial five-year term, with an option to renew for a further two five-year terms. We have already identified five oil prospects on the existing, albeit poor quality, 2D seismic that covers the permit. These prospects appear to be similar to those successfully discovered by our team on the Western Flank of the Cooper Basin, an area that includes prolific oil fields such as Bauer and Callawonga, where our team successfully applied good quality 3D seismic to identify such prospects. One of our least understood, overlooked, but potentially very valuable assets, is the 50% owned Nangwarry CO2 discovery, which was made in January 2020 and located in the south east of South Australia. Although we most certainly believe this to have significant commercial value, it does not appear to be seen in this light by the market - yet. Our investigations have shown that a reliable source of food grade CO2 is in short supply, both in Australia and globally. For example, in April of this year, the USA Compressed Gas Association submitted a letter to US Vice-President Mike Pence expressing concerns that the economic hit caused by the COVID-19 pandemic could affect both the demand for and production of CO2. Industries seeking such a source of CO2 include the beverage, wine and, crucially, medical devices industries. It is certainly significant in this context that South Australia’s most profitable historical well was Caroline-1, a CO2 well that commenced production in 1967 and produced for nearly fifty years, until the field was depleted and abandoned in 2017. Caroline-1 is located near the Nangwarry discovery and serviced many of these aforementioned industries over that 50 year period. We are hopeful that with a successful flow test at Nangwarry-1 we can replicate the success of Caroline-1 as a vitally important source of CO2. 6 The Galilee Basin is still very much in play, and has become a victim of COVID-19, weather and operational circumstance. We fracture-stimulated the Albany-2 well and were about to fracture- stimulate Albany-1 ST1 when these events turned against us. We believe the Albany field has the potential to flow gas at commercial rates. This is supported by the unstimulated flow rate of 230,000 scfd that was recorded during the drilling of Albany-1. We are keen to complete the work in the Albany Field, as the location, geology and east coast demand for gas make the area an attractive prospect. In closing, we would like to thank all our stakeholders who have been extremely dedicated to meeting the strictest of COVID-19 standards across our operations during this challenging period. Pleasingly, we have recorded no cases of COVID-19 and our operations have continued unabated, and supported by enhanced health and safety practices which have now been adopted in our office and on-site. To the team at Vintage, we thank you for all your hard work and your delivery as a team and we also would like to thank the Board for its ongoing support of the path and direction taken by Vintage since listing. And finally, it goes without saying that we would like to thank those shareholders that have been with us from the start of this journey and welcome all the new shareholders that have come on to our register over the past twelve months. We have already shown what we are capable of and we look forward to delivering sustainable returns to you for many years to come. Reg Nelson Chairman Neil Gibbins Managing Director Our experienced and knowledgeable team has delivered two discoveries during the last, most challenging, financial year Vintage Energy Ltd Annual Report 2020 7 7 Vintage Energy Ltd Annual Report 2020Review of operations New discoveries have given Vintage line of sight to near-term production and cash flow Cooper / Eromanga Basins, Queensland and South Australia ATP 2021 (Vintage 50% and operatorship, Metgasco Ltd (“Metgasco”) 25% and Bridgeport (Cooper Basin) Pty Ltd 25%) ATP 2021 is a 370 km2 permit, located on the Queensland side of the Cooper/Eromanga Basins, which was identified as a prospective permit with multiple leads and prospects mapped using historic 2D and recent 3D seismic data. 8 The permit is adjacent to a number of gas and oil fields, and associated pipelines with facilities, that have produced over 600 Bcf of gas and 11 MMbbl of oil. The target zones within the leads and prospects in the permit are Permian gas and Jurassic oil reservoirs, which have historically been the main producing zones in the Cooper/ Eromanga Basins. The Vali structure is a robust Permian anticlinal closure, some 10km2 in area, located in the southern part of the permit. Permian Toolachee and Patchawarra formation sandstones within the closure are proven producing reservoirs on the southern flank of the Nappamerri Trough. The Vali structure was identified on the 2016 Snowball 3D seismic survey and is approximately three kilometres from Kinta-1, a well drilled in 2003 that intersected gas charged sands in the Patchawarra and Toolachee formations. The SLR-185 rig, a 1250 HP rig capable of drilling to 3,500 metres, was secured and mobilised to site to drill the Vali-1 gas exploration well. Vali-1 spudded on 15 December 2019 and was side- tracked during drilling, reaching a total depth (“TD”) of 3,217 metres measured depth (“MD”), in basement, on 10 January 2020. The well was cased and suspended as a new field gas discovery with gas pay interpreted in the Patchawarra Formation. Gas pay was also interpreted in a Triassic aged Nappamerri Group sandstone unit and the Permian aged Toolachee Formation and Tirrawarra Sandstone. Oil shows were recorded in the Jurassic aged Westbourne and Birkhead formations, increasing the prospectivity for oil in nearby Jurassic closures. Post drill volumetric assessments for the discovery were completed, with ERCE independently certifying 37.7 Bcf (gross) 2C Gas Contingent Resources in the Patchawarra Formation of the Vali gas field, which was estimated from over 80 metres of interpreted log net gas pay (porosity cut-off of 6%) over a gross 312 metre interval in the Patchawarra Formation. Potential exists to increase the size of resource with further testing/drilling addressing possible pay in the Toolachee Formation, Tirrawarra Sandstone and Nappamerri Group. Vali Gas Field Patchawarra Formation (100%) Gas in Place (Bcf) Contingent Resource (Bcf) Low 34.0 Mid 84.2 High 216.0 1C 15.2 2C 37.7 Vali Gas Field Patchawarra Formation (50%, Net to Vintage) Gas in Place (Bcf) Contingent Resource (Bcf) Low 17.0 Mid 42.1 High 108.0 1C 7.6 2C 18.8 3C 97.0 3C 48.5 Notes: 1. Contingent Resource volumes have shrinkage applied to account for CO2 and include only hydrocarbon gas. No allowance for Fuel and Flare has been made. 2. ERCE GIIP volumes and Contingent Resources presented in the tables are the probabilistic totals for all 19 Patchawarra reservoir intervals. 3. Probabilistic totals have been estimated using the Monte Carlo method. 4. Estimates for contingent resources have not been adjusted for development risk. 5. The resources have been classified and estimated in accordance with the PRMS. 6. These resource estimates are as of 2 March 2020 and first disclosed in an ASX release on 3 March 2020. 7. Vintage is not aware of any new data or information that materially affects the estimate above and that all material assumptions and technical parameters continue to apply and have not materially changed. 9 Vintage Energy Ltd Annual Report 2020 Review of operations continued... Subsequent to year end, fracture stimulation work was undertaken by Condor Energy Services Pty Ltd (“Condor”) in July 2020, with six stimulation stages placed, five in the Patchawarra Formation and one in the deeper Tirrawarra Sandstone. This was followed by a flow test of the Vali-1 ST1 well, with a stabilised raw gas rate, over a two-day period, of 4.3 MMscfd observed through a 36/64“choke at 942 psi (flowing well-head pressure). A development concept for the Vali Field has been completed and estimates a field life of around 20 years. PRL 211 (Vintage earning 42.5% and operatorship, Metgasco earning 21.25%, Bridgeport (Cooper Basin) Pty Ltd earning 21.25% and Senex Energy Ltd 15%) PRL 211 is a 98.49 km2 retention licence that is close to infrastructure and located adjacent to ATP 2021, on the South Australia side of the Cooper Eromanga Basin. Vintage identified prospectivity in PRL 211, similar to that in ATP 2021, and farmed- in to the permit in November 2019 along with its ATP 2021 joint venture partners. The farm-in to PRL 211 will see Senex free carried through the drilling of the first well, with Vintage appointed operator. 10 PRL 211 has an initial five-year term expiring in October 2022, with an option to renew the permit for a further five years. The main target is the Odin structure, which is fully covered by recent 3D seismic and has gas potential in the Patchawarra and Toolachee formations. Odin is located near the producing reservoirs at the Bow, Beckler and Dullingari fields. Stratigraphically trapped gas outside of structural closure, similar to that seen in the Beckler-Bow field area is also possible within the permit. The Odin prospect straddles the border between PRL 211 and ATP 2021 and appears similar in form to the Vali discovery. Under the terms of the farm-in, Vintage, Bridgeport and Metgasco will drill a well into the Odin structure (with Vintage paying 50% of the estimated cost of the well – approximately $2.5 million contribution by Vintage for 42.5% equity). All further work, including the potential to stimulate and flow test the Odin well will revert to equity share post farm-in. The well will be located in PRL 211 with the drilling targeted to take place in 2021. The Odin prospect is a four-way dip closure situated on a structural nose that plunges north-eastwards into the Nappamerri Trough. It is prospective for gas in multiple sands of the Permian aged formations. Seismic mapping indicates that the Toolachee Formation has approximately eight metres of structural relief over nearly 5.2 km2, a chance of success (“COS”) of 40% and a high chance of development. The Patchawarra Formation has 15 metres of structural relief over nearly 2.5 km2, a COS of 32% and a high chance of development. Odin Prospective Resources PRL 211 & ATP2021 combined (Bcf) Formation Toolachee Patchawarra Total Net to Vintage Notes: 1U low estimate 2U best estimate 3U high estimate 1.2 2.4 3.6 1.6 4.1 8.5 12.6 5.7 13.5 29.1 42.6 19.0 1. Net to Vintage and 42.5% of the prospective resources in PRL 211. 2. The estimated quantities of petroleum that may potentially be recovered by the application of a future development project(s) relate to undiscovered accumulations. 3. These estimates have both an associated risk of discovery and a risk of development. 4. These prospective resources are estimated as of 14 October 2019 and first reported to the ASX on 22 November 2019. 5. Further exploration, appraisal and evaluation is required to determine the existence of a significant quantity of potentially moveable hydrocarbons. 6. The resources have been classified and estimated in accordance with the Petroleum Resource Management System (PRMS). 7. The prospective resources have been estimated based on the interpretation of 3D seismic integrated with offset well data. Probabilistic methods have been used to estimate the prospective resource in individual reservoirs and the reservoirs have been summed arithmetically. 8. Vintage is not aware of any new data or information that materially affects the estimate above and that all material assumptions and technical parameters continue to apply and have not materially changed. 9. It is expected that the prospect will be drilled in the second half of FY21, following seismic reprocessing and mapping in December 2019 that confirmed the optimal well location. This reprocessing work did not change the volumetrics. 10. Resource estimates are net of shrinkage. 11 Vintage Energy Ltd Annual Report 2020 Review of operations continued... Block CO2019-E (PELA 679) (Vintage 100% on award) Vintage was successful in bidding for Block CO2019-E (“PELA 679”) in the south west of the Cooper Basin in South Australia. PELA 679 forms one of five hydrocarbon exploration licence blocks released for competitive bidding by the South Australian Department of Energy and Mining in 2019. Once an appropriate land access agreement is in place with the Dieri Aboriginal Corporation RNTBC and the State Government, Vintage will have a 100% interest in the permit, which will provide options relating to the financing of the firm work program through the potential introduction of a joint venture partner/s. PELA 679 has both Permian and Jurassic oil potential, with cumulative oil production of 4.5 MMbbl from two nearby fields, one being the Worrior Field immediately to the north east. The permit covers a total area of 393 km2 and has primarily been targeted for oil exploration. Seismic data is limited with the majority being poor quality 2D. 12 The first exploration well in the region was Pando-1 which was drilled in 1966 and targeted for oil and gas within a large four-way closure. Despite Jurassic oil shows, the well was plugged and abandoned, with Stuart Petroleum Ltd drilling the Worrior-1 wildcat 37 years later, 750 metres to the south east of Pando-1. 50 km2 of 3D seismic and ten development wells have resulted in production in excess of 4 MMbbl of oil to date from the Worrior oil field (Senex Energy 70%, Cooper Energy 30%), primarily from the McKinlay Member, Birkhead Formation and Hutton Sandstone. The committed work program for the permit over the initial five year licence term includes geological and geophysical studies comprising basin modelling, petrophysics and a rock physics trending study, acquisition of 100 km2 of 3D seismic and the drilling of two wells. Vintage has identified three Jurassic four-way closures and one Permian Patchawarra Formation stratigraphic play from the sparse 2D seismic it has mapped to date. The “morphology” of basement-influenced Jurassic structures located up-dip and along trend of Permian stratigraphic hydrocarbons, is analogous to Beach Energy Ltd’s prolific Western Flank play, where the Pennington Oil Field and ultimately the Bauer Field are up-dip of Permian stratigraphically trapped gas of the Udacha and Middleton Fields. Galilee Basin, Queensland Deeps Joint Venture (Vintage 30%, Comet Ridge Ltd (“Comet”) 70% and operator) The stimulation of Albany-2 took place in December 2019, with the stimulation of Albany-1 ST1 currently on hold. Albany-1 ST1 was drilled and cased to a total MD of 2,822 metres, providing access to the full reservoir section for stimulation and evaluation. The drilling of Albany-2 and the side-track of Albany-1 confirmed the Albany Field structural mapping and the presence of gas between the two wells, which are approximately seven kilometres apart. Log analysis at Albany-2 identified gas in multiple sands of the Lake Galilee Sandstone reservoir section, demonstrating that reservoir sandstones extend across the Albany Field and also showed maximum porosities up to 15% (higher than those at Albany-1 ST1 over small intervals). Some stratigraphic variation was observed between Albany-1 ST1 and Albany-2. A total of 62 metres of core was acquired in Albany-2. X-Ray diffraction analysis, which examines the constituent minerals of the rock to assist with the selection of the stimulation fluid, was undertaken on cored reservoir samples. Gas shows were observed in the B sand section of Albany-1 ST1, which had flowed gas to surface at 0.23 MMscfd in 2018 without any fracture stimulation. Shows of equal and better magnitude were evident in multiple sands in the section not penetrated in Albany-1, offering encouragement for what a flow test of the full reservoir section might offer post-stimulation. In Albany-2, log analyses and gas shows indicate the presence of gas in each of the Lake Galilee Sandstones. Vintage reached the pre-determined Stage 2 funding point of $10 million (gross) during the year, which triggered an increase in Vintage’s equity in the Galilee Basin Deeps Joint Venture (“GBDJV”) from 15% to 30%. Albany-2 was the first well to be stimulated in the Lake Galilee Sandstone of the Galilee Basin, and it is likely there will be optimisation of the stimulation approach based on the outcomes from this well and Albany-1 ST1. A two well appraisal drilling program in the Albany gas field was completed in the first half of the year. 13 Vintage Energy Ltd Annual Report 2020Review of operations continued... Vintage Contingent Resource, Recoverable Gas Contingent Resource (PJ, net to Vintage) Tenement Vintage Interest Field Method ATP 744 30% Albany Probabilistic 1C 17 2C 46 3C Chance of Development Product Type 125 High Gas Notes: 1. As at 31 July 2018 and first detailed in the 2018 Prospectus 2. Albany Field previously named the Carmichael Field 3. Vintage acquired a 30% interest in the Albany structure (in the Galilee Sandstone reservoir – “Deeps”) after the drilling and testing of Albany-1, the completion of the Koburra 2D seismic program and the drilling of Albany-2 4. Reference Comet Ridge Market announcement of 5 August 2015 quoting independently certified Contingent Resources 5. Estimates are in accordance with the PRMS (SPE, 2007) and Guidelines for Application of the PRMS (SPE, 2011) 6. No Reserves were estimated 7. Sales gas recovery and shrinkage have been applied to the Contingent Resource estimation, with losses included from field use, as well as fuel and flare gas 8. Vintage is not aware of any new data or information that materially affects the estimate above and that all material assumptions and technical parameters continue to apply and have not materially changed 14 Onsite operations at the Albany gas field were suspended due to heavy rainfall and resultant flooding of the area in February 2020. Currently all operational activity, including stimulation of Albany-1 ST1, is on hold. Otway Basin, South Australia/Victoria PEL 155 (Vintage 50%, Otway Energy Pty Ltd 50% and operator) Easternwell Rig 106 spudded the Nangwarry-1 well on 1 December 2019, with TD reached at 4,300 metres MD in the Pretty Hill Formation. The fully automated capability of the rig improved the efficiency of the drilling process, with drilling finishing ahead of schedule. Gas shows were observed in the top Pretty Hill Sandstone and mid Pretty Hill Sandstone. Six reservoir fluid samples were taken at three depth intervals within the top Pretty Hill Sandstone, with laboratory-based analyses of samples yielding CO2 content in excess of 90%. These results and evaluation of wireline log data indicate a CO2 column that is 90 metres, with a further 45 metres subject to confirmation by testing. This is a 25-70 metre increase over the initially estimated 65 metre column. The well has been cased and suspended for further evaluation, including the mid Pretty Hill Sandstone, which could not be fully evaluated at the time. Subsequent to year end, a recoverable CO2 booking for the Nangwarry-1 discovery was made. Employing a method consistent with the June 2018 Society of Engineers Petroleum Resources Management System (“PRMS”) methodology, a gross Best Case of 25.1 Bcf recoverable CO2 was estimated by ERC Equipoise Pte Ltd (“ERCE”). Under PRMS, volumes of non-hydrocarbon by- products cannot be included in any Reserves or Resources classification. ERCE assessed the sales gas volumes attributable to the Nangwarry-1 discovery using a methodology consistent with that prescribed by the PRMS, with its independent assessment of a Best Case 25.1 Bcf gross recoverable CO2 made for the top Pretty Hill Sandstone of the Nangwarry CO2 discovery (12.6 Bcf net to Vintage). This compares extremely well with other commercial Otway Basin CO2 fields such as Caroline (~15 Bcf), which was in production for approximately 50 years, and Boggy Creek (~14 Bcf). Gross PEL 155 Nangwarry Field Pretty Hill Sandstone CO2 Sales Gas (Bcf) Unrisked hydrocarbon Contingent Resources (Bcf) Low 7.8 Best 25.1 High 82.1 1C 0.8 2C 2.6 3C 8.8 Net PEL 155 Nangwarry CO2 Field Pretty Hill Sandstone CO2 Sales Gas (Bcf) 50% VEN Unrisked hydrocarbon Contingent Resources (Bcf) 50% VEN Low 3.9 Best 12.6 High 41.1 1C 0.4 2C 1.3 3C 4.4 15 Vintage Energy Ltd Annual Report 2020Review of operations continued... Notes: 1. As at 31 August 2020 and first detailed in the ASX release of the same date. 2. Recoverable CO2 and Contingent Resource estimates reported here are ERCE estimates. 3. Gross Contingent Resources represent a 100% total of estimated recoverable hydrocarbon volumes. 4. Resource estimates have been made and classified in accordance with the PRMS guidelines and methodology. 5. Recoverable CO2 estimates have been made and classified using a method consistent with the PRMS guidelines and methodology. 6. Net recoverable CO2 attributable to Vintage represents the fraction of gross recoverable CO2 allocated to Vintage, based on its 50% interest in PEL 155. 7. Volumes reported here are “unrisked” in the sense that no adjustment has been made for the risk that the project may not be developed in the form envisaged or may not go ahead at all (i.e. no Chance of Development factor has been applied). 8. Chance of Development for the recoverable CO2 has been estimated to be 75% by Vintage and agreed by ERCE. This is based on the ability to establish a skid mounted processing facility at the well-head, adequate road access for trucks to transport the CO2 to market, similar reservoirs developed nearby such as Caroline-1, and high downstream demand for food grade CO2. 9. Hydrocarbon Contingent Resources have been sub-classified as “Development Unclarified” under the PRMS by ERCE and are assigned as Consumed in Operations, that is used as fuel for the CO2 plant. The key contingencies are a final investment decision on development, committing to a CO2 sales agreement, any other necessary commercial arrangements, and obtaining the usual regulatory approvals for production. 10. Recoverable CO2 volumes shown have had shrinkage applied to account for methane and include only CO2 gas. 11. Recoverable CO2 and Contingent Resources presented in the tables are the probabilistic totals for the Pretty Hill Sandstone reservoir interval. 12. Probabilistic totals have been estimated using the Monte Carlo method. 13. Vintage is not aware of any new data or information that materially affects the estimate above and that all material assumptions and technical parameters continue to apply and have not materially changed 16 An extended production test of the Nangwarry-1 well is currently being designed and targeted for the end of 2020. Discussions are progressing with a number of parties interested in the various stages of development, production, and purchase of Nangwarry CO2. The Cervantes prospect sits within L14, a 39.8 km2 Perth Basin production licence granted over the Jingemia oil field and surrounds. The licence is in good standing and not due to expire until June 2025. To earn 30%, Vintage will pay for 50% of the cost of the well, and $200k of evaluation and exploration. PEP 171 (Vintage 25% and operatorship, and Cooper Energy Ltd 75%) In June 2020, the Victorian Government legislated that the moratorium, banning any petroleum exploration and production in the onshore areas of Victoria, will be officially lifted from 1 July 2021. On that date, the first five-year term of the PEP 171 licence will be restarted. New regulations are being drafted and an updated exploration program will be proposed and negotiated with the regulator prior to the restart of the licence. GSEL 672 (Vintage 100%) A Gas Storage Exploration Licence (“GSEL”) was granted to Vintage covering a portion of the South Australian Otway Basin to the south of PEL 155. To date, activities have been limited to technical evaluation, analysis, and review of potential gas storage options, which include the commercial aspects of those options. Perth Basin, Western Australia Cervantes Structure (L 14) (Vintage earning 30%, Metgasco earning 30% and RCMA Australia Pty Ltd (“Jade”), 40%) Vintage executed a farm-out agreement with Metgasco and Jade, which will be free carried through the drilling of the Cervantes oil prospect. The joint venture is targeting to spud the well in 2021 and has an option to drill a second well into a separate prospect. The proposed Cervantes-1 well is expected to cost $3.7 million (net), with any well costs above a cap of $8 million (gross) reverting to Vintage’s joint venture equity level of 30%. The Cervantes structure is located on an oil discovery trend, comprised of the Hovea, Jingemia and Cliff Head oil fields. These fields, in total, have produced in excess of 27 MMbbl of oil from Permian reservoirs in the Perth Basin and lie within an oil fairway around the western and northern section of the basin. The Cervantes structure is a high-side fault trap with multiple Permian reservoir units, sharing strong similarities with the offset oil fields in terms of structure, potential reservoirs, and access to a mature oil source rock. The Permian reservoir targets in the prospect are the prolific Dongara, Kingia and High Cliff sandstones which are expected to yield a combined gross 2U Best Estimate of 15.3 MMbbl (4.6 MMbbl net to Vintage) of oil. Cervantes has a chance of success of 28% and a high chance of development due to its proximity to infrastructure and existing oil and gas fields. The opportunity for rapid conversion of prospective resources to producing reserves exists via a 3rd party oil processing and operations agreement with L14 operator Jade, which owns and operates the nearby Jingemia oil processing and export facility. 17 Vintage Energy Ltd Annual Report 2020Review of operations continued... Cervantes Prospective Oil Resource (MMbbl) Sandstone 1U low estimate 2U best estimate 3U high estimate Dongarra Kingia High Cliff Total Net to Vintage Notes: 3.7 2.2 0.1 6.0 1.8 7.4 7.1 0.8 15.3 4.6 14.6 22.3 5.0 41.9 12.6 1. Volumetrics sourced from Metgasco. 2. The estimated quantities of petroleum that may potentially be recovered by the application of a future development project(s) relate to undiscovered accumulations. 3. These estimates have both an associated risk of discovery and a risk of development. 4. These prospective resources are estimated as of 10 September 2019 and this was the first time they were reported. 5. Further exploration, appraisal and evaluation is required to determine the existence of a significant quantity of potentially moveable hydrocarbons. 6. The resources have been classified and estimated in accordance with PRMS. 7. The prospective resources have been estimated based on the interpretation of 3D seismic integrated with offset well data. 8. Probabilistic methods have been used to estimate the prospective resource in individual reservoirs and the reservoirs have been summed arithmetically. 9. Vintage is not aware of any new data or information that materially affects the estimate above, with all material assumptions and technical parameters continuing to apply and have not materially changed. 10. It is expected that the prospect will be drilled in the second half of FY21 and that no further material exploration activities, including studies, further data acquisition and evaluation work will be undertaken prior to that activity. 11. Resource estimates are net of shrinkage. The Cervantes Joint Venture has retained Aztech Well Construction Pty Ltd (“Aztech”) to design and manage the drilling of the Cervantes-1 exploration well. Aztech has a wealth of experience in the north Perth Basin, including managing the recent successful Beharra Springs Deep exploration well. Aztech conducted the initial scoping of the well-plan and has started the well design and planning, including identification and sourcing of long lead items. A further survey of the proposed well site was recommended by the environmental authorities and will be conducted in September 2020. Final project environmental approvals are anticipated by the end of 2020, which will allow for drilling in 2021. Bonaparte Basin, Northern Territory EP 126 (Vintage 100%) The Northern Territory (“NT”) Government advised that approximately 50% of the NT could be declared as reserved areas and is currently undertaking a consultation process with those petroleum companies affected by its proposal. Under the proposal, Sites of Conservation Significance (“SOCS”) are one of the categories of land that will be declared ‘no go zones’ for petroleum exploration and production and be excised from pre-existing and future petroleum licence areas. A considerable portion of the prospective areas within Vintage’s EP 126, in the Bonaparte Basin, is affected by the proposed reserved area as SOCS. 18 A submission has been made to the NT Government and clearly outlines Vintage’s view that past, current and future approved land use within the majority of EP 126 are inconsistent with the declaration of a reserved area on the basis of a SOCS. Vintage considers the extent of reserved area is inconsistent with past petroleum activities, current pastoral activities and future approved activities associated with development of the surrounding Project Sea Dragon prawn farm. Vintage also considers that effective environmental management, as approved under existing petroleum regulations, has already been demonstrated by past activities in EP 126 and is sufficient to minimise any environmental impact in the area. The timeframe of the government process is currently unclear. Vintage plans to test the already drilled Cullen-1 well to better understand the ability of the well to flow natural gas. Vintage believes that there is an excellent opportunity to find commercial quantities of natural gas in EP 126 which could provide favourable economic benefit to the Northern Territory, in terms of job creation and the delivery of much needed gas to local industry and the general market. 19 Vintage Energy Ltd Annual Report 2020Reserves and Resources Statement 20 Reserves and Resources Statement At 30 June 2020, Vintage did not hold any booked Reserves. Contingent Resources During the reporting period, Vintage acquired its second tranche of 15% equity interest for the ‘Deeps Joint Venture’, through completion of Stage 2 of the two-stage farm-in process. Consequently, at June 30 2020, Vintage had earned a 30% share of the independently certified contingent resource booking for the Albany Gas Field. In addition, the ATP 2021 Joint Venture discovered the Vali gas field and booked a Contingent Resource on that discovery. The table below shows the movement in 2C resource during the period 1 July 2019 to 30 June 2020. Movement in 2C Resource Net to Vintage Basin 30-Jun-19 Acquisitions/ Divestments Contingent Resources to Reserves Revisions 30-Jun-20 Galilee Basin Cooper Basin Total 23 0 23 23 0 23 0 0 0 0 21 21 46 21 67 During 2015, SRK Consulting (Australia) Pty Ltd, (“SRK”), conducted a technical analysis of the available Carmichael Field seismic and well data for Comet Ridge Ltd. Based on the seismic and petrophysical interpretations and assessment consistent with the SPE Petroleum Resource Management System (SPE, 2007), SRK provided an estimate of Contingent Resources for the field. SRK has also been provided with the well data from Albany-1 and is of the view the well results are consistent with their estimates of contingent resources. Vintage notes that the Albany-2 well has been drilled and cased and suspended and is not aware of any new data or information from that activity or otherwise that materially affects the relevant assessment above and that all material assumptions and technical parameters continue to apply and have not materially changed. During February/March 2020, ERC Equipoise Pte Ltd (“ERCE”) carried out an independent assessment of the resources in the Patchawarra Formation of the Vali gas field. The results of these two assessments are presented in the following tables: Vintage Contingent Resource by Tenement Contingent Resource (PJ, Net to Vintage) Tenement Vintage Interest Field Method 1C 2C 3C Chance of Development Product Type ATP 744 30% Albany Probabilistic ATP 2021 50% Vali Probabilistic 16 8 46 21 126 53 High 85% Gas Gas Vintage Contingent Resource by Geographical Area Contingent Resource (PJ, Net to Vintage) Tenement Vintage Interest Field Method 1C 2C 3C Chance of Development Product Type ATP 744 30% Albany Probabilistic ATP 2021 50% Vali Probabilistic 16 8 46 21 126 53 High 85% Gas Gas 21 Vintage Energy Ltd Annual Report 2020 Reserves and Resources Statement (continued) – “Deeps”) after the drilling and testing of Albany-1, which is close to where Carmichael-1 flowed gas. Standard Notes on ATP 744 assessment: Reserves and resources are reported in accordance with the definitions of reserves, and guidelines set out in the 1. During the reporting period, Vintage acquired a 15% interest in the Carmichael structure (in the Galilee Sandstone reservoir Petroleum Resources Management System (PRMS) approved by the Board of the Society of Petroleum Engineers in 2007. 2. Estimates are in accordance with the Petroleum Resources Management System (SPE, 2007) and Guidelines for This Report has been prepared in accordance with the Code for the Technical Assessment and Valuation of mineral and Petroleum Assets and Securities for Independent Expert Reports 2005 Edition (“The VALMIN Code”) as well 3. No Reserves were estimated. as the Australian Securities and Investment Commission (ASIC) Regulatory Guides 111 and 112. 4. Probabilistic methods were used. 5. Sales gas recovery and shrinkage have been applied to the Contingent Resource estimation. The losses include those Application of the PRMS (SPE, 2011). from the field use, as well as fuel and flare gas. Reserves Evaluator 6. These volumes were first reported by Vintage in the September 2018 prospectus for the Initial Public Offering of shares in Vintage and prior to that by the Comet Ridge Ltd. announcement of 5 August 2015. SRK Consulting (Australasia) Pty Ltd – Carmichael Structure Contingent 7. The chance of development is classified as high as several commercialisation possibilities exist for future gas supply export. Resource Assessment There is the potential for a gas supply to nearby industrial sites. In addition, gas pipeline spurs could be constructed to connect with the major trunklines at Mooranbah or Barcaldine which would provide access to the general Queensland SRK is an independent, international group providing specialised consultancy services, with expertise in petroleum domestic market. Planning studies are underway by pipeline proponents and the Deeps Joint Venture has an memorandum studies and petroleum related projects. In Australia, SRK have offices in Brisbane, Melbourne, Newcastle, Perth of understanding (“MOU”) with APA Group with respect to a potential pipeline connection including conceptual studies to and Sydney and globally in over 40 countries. SRK has completed petroleum reserve and resource assessments construct larger pipelines to connect more directly into the LNG supply infrastructure. A direct route to Gladstone is one for many clients in Australia and internationally. possibility and another is to the hub at Wallumbilla. In May 2019, Comet Ridge Ltd. and Vintage entered into a non-binding The Contingent Resource for the Carmichael Structure referred to in this report is derived from an independent Memorandum of Understanding (‘MOU’) with APA Group as a framework of cooperation under which a pipeline could be report by Dr Bruce McConachie, an Associate Principal Consultant with SRK Consulting (Australasia) Pty Ltd, an built to connect with existing infrastructure. Jemena Gas Network (‘Jemena’; a subsidiary of SGSP (Australia) Assets Pty independent petroleum reserve and resource evaluation company. He has disclosed to Vintage, the full nature of Ltd) was reported (AFR, 10 May 2017) as undertaking feasibility studies for a possible extension from Mt. Isa to SE the relationship between himself and SRK, including any issues that could be perceived by investors as a conflict Queensland of its Northern Gas Pipeline (‘NGP’) (currently under construction to connect Tennant Creek in the Northern of interest. Territory with Mt. Isa). Following the NT Government’s announcement (NT News 17 April 2018) to lift the moratorium on fracture stimulation, Jemena intends (Northern Star, 17 April 2018) to progress its plans to extend the NGP. Dr McConachie is a geologist with extensive experience in economic resource evaluation and exploration. He is a Comet Ridge is exploring the coal seam gas potential of the overlying “Shallows” and at present is focussing on the southern member of the American Association of Petroleum Geologists, Society of Petroleum Engineers and Australasian portions of ATP 744 and ATP 1015. This may provide the opportunity for shared facilities and/or cooperation in the event Institute of Mining and Metallurgy. His career spans over 30 years and includes production, development and of success in both the “Shallows” and “Deeps” areas. exploration experience in petroleum, coal, bauxite and various industrial minerals, covering petroleum exploration programs, joint venture management, farm-in and farm-out deals, onshore and offshore operations, field evaluation and development, oil and gas production and economic assessment, with relevant experience assessing petroleum Notes on ATP 2021 assessment: resource under PRMS code (2007). 1. Gas In Place and Contingent Resource estimates reported here are ERCE estimates. The Carmichael Structure Contingent Resources information in this report has been issued with the prior written 2. Gross Contingent Resources represent a 100% total of estimated recoverable volumes. consent of Dr McConachie in the form and context in which it appears. His qualifications and experience meet the 3. Resource estimates have been made and classified in accordance with the Petroleum Resources Management System requirements to act as a Competent Person to report petroleum reserves in accordance with the Society of Petroleum Engineers (“SPE”) 2007 Petroleum Resource Management System (“PRMS”) Guidelines as well as the 4. Net Contingent Resources attributable to Vintage represent the fraction of Gross Contingent Resources allocated to 2011 Guidelines for Application of the PRMS approved by the SPE. (“PRMS”). Vintage, based on its 50% interest in ATP 2021. 5. Volumes reported here are “unrisked” in the sense that no adjustment has been made for the risk that the project may not be developed in the form envisaged or may not go ahead at all (i.e. no Chance of Development factor has been applied). ERC Equipoise Pte Ltd – Vali Contingent Resource Assessment 6. Chance of Development for the Contingent Resources shown here has been estimated to be 85% by Vintage and agreed ERCE is an independent consultancy specialising in petroleum reservoir evaluation. Except for the provision of by ERCE. This is based on proximity to existing infrastructure, development of similar reservoirs by adjacent fields and high professional services on a fee basis, ERCE has no commercial arrangement with any other person or company downstream gas demand. involved in the interests that are the subject of this Contingent Resources evaluation. 7. Contingent Resources have been sub-classified as “Development Unclarified” under the PRMS by ERCE. 8. Contingent Resources volumes shown have had shrinkage applied to account for CO2 and include only hydrocarbon gas. The work has been supervised by Mr Adam Becis, Principal Reservoir Engineer of ERCE’s Asia Pacific office who has over 14 years of experience. He is a member of the Society of Petroleum Engineers and also a member of 9. Contingent Resources have been converted from volumes to energy values using a conversion of 1 Bcf = 1.1PJ. the Society of Petroleum Evaluation Engineers. 10. Contingent Resources presented in the tables are the arithmetic sum of probabilistic totals for all 19 Patchawarra reservoir No allowance for Fuel and Flare has been made. intervals. 11. Probabilistic totals have been estimated using the Monte Carlo method. 22 Reserves and Resources Statement (continued) Standard Reserves and resources are reported in accordance with the definitions of reserves, and guidelines set out in the Petroleum Resources Management System (PRMS) approved by the Board of the Society of Petroleum Engineers in 2007. This Report has been prepared in accordance with the Code for the Technical Assessment and Valuation of mineral and Petroleum Assets and Securities for Independent Expert Reports 2005 Edition (“The VALMIN Code”) as well as the Australian Securities and Investment Commission (ASIC) Regulatory Guides 111 and 112. Reserves Evaluator SRK Consulting (Australasia) Pty Ltd – Carmichael Structure Contingent Resource Assessment SRK is an independent, international group providing specialised consultancy services, with expertise in petroleum studies and petroleum related projects. In Australia, SRK have offices in Brisbane, Melbourne, Newcastle, Perth and Sydney and globally in over 40 countries. SRK has completed petroleum reserve and resource assessments for many clients in Australia and internationally. The Contingent Resource for the Carmichael Structure referred to in this report is derived from an independent report by Dr Bruce McConachie, an Associate Principal Consultant with SRK Consulting (Australasia) Pty Ltd, an independent petroleum reserve and resource evaluation company. He has disclosed to Vintage, the full nature of the relationship between himself and SRK, including any issues that could be perceived by investors as a conflict of interest. Dr McConachie is a geologist with extensive experience in economic resource evaluation and exploration. He is a member of the American Association of Petroleum Geologists, Society of Petroleum Engineers and Australasian Institute of Mining and Metallurgy. His career spans over 30 years and includes production, development and exploration experience in petroleum, coal, bauxite and various industrial minerals, covering petroleum exploration programs, joint venture management, farm-in and farm-out deals, onshore and offshore operations, field evaluation and development, oil and gas production and economic assessment, with relevant experience assessing petroleum resource under PRMS code (2007). The Carmichael Structure Contingent Resources information in this report has been issued with the prior written consent of Dr McConachie in the form and context in which it appears. His qualifications and experience meet the requirements to act as a Competent Person to report petroleum reserves in accordance with the Society of Petroleum Engineers (“SPE”) 2007 Petroleum Resource Management System (“PRMS”) Guidelines as well as the 2011 Guidelines for Application of the PRMS approved by the SPE. ERC Equipoise Pte Ltd – Vali Contingent Resource Assessment ERCE is an independent consultancy specialising in petroleum reservoir evaluation. Except for the provision of professional services on a fee basis, ERCE has no commercial arrangement with any other person or company involved in the interests that are the subject of this Contingent Resources evaluation. The work has been supervised by Mr Adam Becis, Principal Reservoir Engineer of ERCE’s Asia Pacific office who has over 14 years of experience. He is a member of the Society of Petroleum Engineers and also a member of the Society of Petroleum Evaluation Engineers. 23 Vintage Energy Ltd Annual Report 2020 Directors’ Report 24 24 Directors’ Report The Directors of Vintage Energy Limited (“Vintage” or “the Company”) present their report together with the financial statements of the Company for the year ended 30 June 2020 and the Independent Audit Report thereon. Director Details The following persons were Directors of Vintage during or since the end of the financial year: Reg Nelson | Chairman Reg Nelson has a long and distinguished career in the Australian petroleum industry and is widely respected within commercial and government circles, for his successful and innovative leadership. As Managing Director of ASX-listed Beach Energy Limited (“Beach”), until retiring from the position in 2015, he led the company to a position as one of Australia’s top mid-tier oil and gas companies. He was formerly Director of Mineral Development for the State of South Australia, a Director of the Australian Petroleum Production and Exploration Association (“APPEA”) for eight years and was APPEA Chairman from 2004 to 2006. He is a Director of petroleum exploration company FAR Limited and has been a Director of many Australian Securities Exchange (“ASX”) listed companies. Reg was awarded the Reg Sprigg Medal by APPEA in 2009 in recognition of his industry contribution. Other Directorships - FAR Limited (since May 2015). Committee memberships - Audit and Risk, Remuneration and Nomination. Interest in shares and options Ordinary shares Options Founder’s Rights 13,494,696 1,000,000 1,320,941 Neil Gibbins | Managing Director Neil Gibbins has over 35 years of technical and leadership experience in the petroleum industry in a wide variety of regions in Australia and internationally and has been involved in many successful exploration, development and corporate acquisition projects. Neil was employed at both Esso Australia and Santos Limited, in initially as a geophysicist and supervisory roles. He moved to Beach in 1997, initially as Chief Geophysicist, and then as Exploration Manager in 2005, and Chief Operating Officer in 2012. Neil was acting CEO in 2015 and led Beach during its merger with DrillSearch Energy Ltd in 2016. He is a member of PESA, SEG, SPE and ASEG. later Other Directorships – Nil. Interest in shares and options Ordinary shares Founder’s Rights Employee incentive rights 12,144,419 1,320,941 1,875,000 Nicholas (Nick) Smart | Non-Executive Director Nick Smart has over 40 years of corporate experience and was a full associate member of the Sydney Futures Exchange, a senior adviser with a national share broking firm, and has significant international and local general management experience. He has participated in capital raisings for numerous private and listed natural resource companies and technology start-up companies. This includes commercialisation of the Synroc process for safe storage of high-level nuclear waste, controlled temperature and atmosphere transport systems and the beneficiation of low rank coals. Committee memberships - Chairman Audit and Risk, Nomination Committee and Remuneration Committee. Interest in shares and options Ordinary shares Options Founders Rights 6,077,967 1,000,000 1,320,941 25 Vintage Energy Ltd Annual Report 2020 Directors’ Report (continued) Significant changes in the state of affairs Two discoveries were made during the year – natural gas at the Vali-1 ST1 well, in the ATP 2021 permit of the Cooper and Eromanga Basins, and CO2, at the Nangwarry-1 well, in the PEL 155 permit, onshore Otway Basin. Ian Howarth | Non-Executive Director Company Secretary 1,000,000 11,966,732 Simon Gray | Company Secretary / Chief Financial Officer Both discoveries have the potential to be on production once appropriate test work and infrastructure connection is The following person was Company Secretary of Ian Howarth spent several years as a mining and oil approved and completed. Vintage during and since the end of the financial year: analyst with Melbourne-based May and Mellor. He had The Company also raised $3,000,000 ($2,250,000 from a share placement and $750,000 from a Share Purchase Plan), a career in journalism as a senior resources writer at the funds from which were primarily used to fracture stimulate and flow test the Vali-1 ST1 gas discovery. The Australian and was the Resources Editor of the Australian Financial Review for 18 years. He created Subsequent events Collins Street Media, one of Australia’s leading Simon Gray has over 35 years' experience as a resources sector consultancies. Clients included Fracture stimulation of the Vali-1 ST1 well over six stages was completed, with five stages in the Patchawarra Formation Chartered Accountant and 20 years as a Partner with APPEA and several listed companies including Shell and one in the deeper Tirrawarra Sandstone. Grant Thornton, a national accounting firm. In his last Australia. His expertise lies in marketing and assisting five years at the firm, he was the national head of in capital raising. Ian has a Certificate in Financial Successful flow testing of the Vali-1 ST1 well delivered a stabilised raw gas rate, over a two-day period, of 4.3 MMscfd Energy and Resources for Grant Thornton. Simon Markets from Securities Institute of Australia. through a 36/64” choke at 942 psi (flowing well-head pressure). retired from active practice in July 2015. His key Other Directorships – Nil. A development concept for the Vali Field was completed and estimates a field life of around 20 years. expertise lies in audit and risk, valuations, due Committee memberships - Audit and Risk, Chair of diligence and ASX Listings. His qualifications include A recoverable CO2 booking for the Nangwarry-1 discovery was made, with a gross Best Case of 25.1 Bcf recoverable the Nomination Committee and Remuneration B.Ec. (Com). He is a Director and Chief Financial CO2 estimated by ERCE. Committee. Officer of minerals exploration company Havilah On 9 July 2020, the Company issued 10,694,444 shares to Directors at $0.036 per share, as part of the share capital Resources Limited and company secretary of several Interest in shares and options placement announced on 30 April 2020. The shares were issued after an Extraordinary General Meeting on 29 June other ASX-listed companies. 2020 obtained shareholder approval for the participation of Directors in the placement. Funds for the placement had Ordinary shares been received prior to 30 June 2020. Options Principal activities Mr. Ian Northcott resigned as Alternate Director to Mr. Ian Howarth, , effective 11 August 2020. Founders Rights Results for the year There has been no significant change in the nature of these activities during the financial year. The Principal activities of the Company during the year On 17 September 2020, the Company announced a share placement and rights issue at $0.06 per share to raise were gas and oil exploration and appraisal. approximately $15,000,000. The funds raised are to be used for: Ian Northcott | Alternative to Ian Howarth (resigned subsequent to year end)  Vali Field connection into the Moomba gathering system;  Drilling of two further Vali Field wells;  Drilling the Odin prospect;    Geological, geophysical and engineering studies. Ian Northcott has 42 years' experience in the upstream petroleum industry in geoscience, reservoir Testing the Nangwarry CO2 discovery; engineering and economics. He was co-founder and Long lead items for drilling the Cervantes prospect; and The Company incurred an operating loss of $2,205,848 Director of PetroVal Australasia Pty Ltd and for 20 for the Financial Year ended 30 June 2020 ($3,422,786 years specialised in the technical and commercial 2019). Efforts over the financial year focused on resource analysis of petroleum Likely developments, business strategies and prospects building a robust portfolio of assets and the execution divestments, mergers, target statements, and capital of work programs associated with earning equity The Company will continue to develop its existing suite of exploration assets and will work to identify other assets and raisings via prospectus. Ian was previously a Director interests in various strategic joint ventures located in corporate opportunities that will grow the Company and enhance shareholder value. of the listed Frontier Petroleum NL. His qualifications prospective petroleum basins onshore in Australia. The are a B.Sc. (Hons) in Geology and Grad.Dip.App. Fin. details of these assets are described in the operations Directors’ meetings & Inv.; he is a Fellow of AusIMM and a member of report in the Annual Report. Association of Petroleum Geologists (AAPG), Society On 30 April 2020 the Company announced a capital The number of meetings of Directors (including meetings of Committees of Directors) held during the year and the of Petroleum Engineers (SPE) and the Society of raise via Placement of 62,500,000 ordinary shares, number of meetings attended by each Director is as follows: Petrophysicists and Well Log Analyst (SPWLA). raising $2,250,000, as well a Share Purchase Plan for 20,833,333 ordinary shares to raise an additional $750,000. Both were over-subscribed. Ian Northcott resigned as Alternate Director to Mr. Ian Howarth, subsequent to year end, effective 11 August 2020. reserves and 1,320,941 Other Directorships – Nil. Dividends Interest in shares and options No Dividends were paid or proposed during the year. Ordinary shares Options Founders Rights 5,911,177 1,000,000 1,320,941 26 Directors’ Report (continued) Significant changes in the state of affairs Two discoveries were made during the year – natural gas at the Vali-1 ST1 well, in the ATP 2021 permit of the Cooper and Eromanga Basins, and CO2, at the Nangwarry-1 well, in the PEL 155 permit, onshore Otway Basin. Both discoveries have the potential to be on production once appropriate test work and infrastructure connection is approved and completed. The Company also raised $3,000,000 ($2,250,000 from a share placement and $750,000 from a Share Purchase Plan), the funds from which were primarily used to fracture stimulate and flow test the Vali-1 ST1 gas discovery. Subsequent events Fracture stimulation of the Vali-1 ST1 well over six stages was completed, with five stages in the Patchawarra Formation and one in the deeper Tirrawarra Sandstone. Successful flow testing of the Vali-1 ST1 well delivered a stabilised raw gas rate, over a two-day period, of 4.3 MMscfd through a 36/64” choke at 942 psi (flowing well-head pressure). A development concept for the Vali Field was completed and estimates a field life of around 20 years. A recoverable CO2 booking for the Nangwarry-1 discovery was made, with a gross Best Case of 25.1 Bcf recoverable CO2 estimated by ERCE. On 9 July 2020, the Company issued 10,694,444 shares to Directors at $0.036 per share, as part of the share capital placement announced on 30 April 2020. The shares were issued after an Extraordinary General Meeting on 29 June 2020 obtained shareholder approval for the participation of Directors in the placement. Funds for the placement had been received prior to 30 June 2020. Mr. Ian Northcott resigned as Alternate Director to Mr. Ian Howarth, effective 11 August 2020. On 17 September 2020, the Company announced a share placement and rights issue at $0.06 per share to raise approximately $15,000,000. The funds raised are to be used for:  Vali Field connection into the Moomba gathering system;  Drilling of two further Vali Field wells;  Drilling the Odin prospect;    Geological, geophysical and engineering studies. Testing the Nangwarry CO2 discovery; Long lead items for drilling the Cervantes prospect; and Likely developments, business strategies and prospects The Company will continue to develop its existing suite of exploration assets and will work to identify other assets and corporate opportunities that will grow the Company and enhance shareholder value. Directors’ meetings The number of meetings of Directors (including meetings of Committees of Directors) held during the year and the number of meetings attended by each Director is as follows: 27 Vintage Energy Ltd Annual Report 2020 Directors’ Report (continued) Significant changes in the state of affairs Two discoveries were made during the year – natural gas at the Vali-1 ST1 well, in the ATP 2021 permit of the Cooper and Eromanga Basins, and CO2, at the Nangwarry-1 well, in the PEL 155 permit, onshore Otway Basin. Board Audit and Risk Remuneration Both discoveries have the potential to be on production once appropriate test work and infrastructure connection is approved and completed. Committee Committee Meetings Board Member A B Nomination Committee Reg Nelson The Company also raised $3,000,000 ($2,250,000 from a share placement and $750,000 from a Share Purchase Plan), the funds from which were primarily used to fracture stimulate and flow test the Vali-1 ST1 gas discovery. 13 13 2 2 2 3 3 2 Ian Howarth 13 13 A 3 3 B 3 3 A 2 2 B 2 2 A 2 2 B 2 2 Neil Gibbins Subsequent events Nick Smart 13 13 13 13 3 3 2 2 2 2 Fracture stimulation of the Vali-1 ST1 well over six stages was completed, with five stages in the Patchawarra Formation and one in the deeper Tirrawarra Sandstone. Notes to the table above: A is the number of meetings held Successful flow testing of the Vali-1 ST1 well delivered a stabilised raw gas rate, over a two-day period, of 4.3 MMscfd B is the number of meetings attended through a 36/64” choke at 942 psi (flowing well-head pressure). A development concept for the Vali Field was completed and estimates a field life of around 20 years. Share Options granted to Management and Directors during the year A recoverable CO2 booking for the Nangwarry-1 discovery was made, with a gross Best Case of 25.1 Bcf recoverable During the financial year 1,000,000 options were issued to the Company Secretary, pursuant to contract. The options CO2 estimated by ERCE. vested immediately, are exercisable at any time until 17 September 2021 and have an exercise price of $0.35 per option. On 9 July 2020, the Company issued 10,694,444 shares to Directors at $0.036 per share, as part of the share capital placement announced on 30 April 2020. The shares were issued after an Extraordinary General Meeting on 29 June The fair value at the date of issue of the options was $20,000. 2020 obtained shareholder approval for the participation of Directors in the placement. Funds for the placement had been received prior to 30 June 2020. Performance Rights granted to Management and Directors during the year Mr. Ian Northcott resigned as Alternate Director to Mr. Ian Howarth, , effective 11 August 2020. During the financial year the company issued 157,500 performance rights to management. The terms of the rights are On 17 September 2020, the Company announced a share placement and rights issue at $0.06 per share to raise disclosed in the Share Based Remuneration section below and had a fair value at the time of issue of $22,049. approximately $15,000,000. The funds raised are to be used for: In addition to those issued to management above, on 1 March 2020, 725,000 performance rights relating to management vested and were converted into ordinary shares on satisfaction of a performance condition.  Vali Field connection into the Moomba gathering system;  Drilling of two further Vali Field wells;  Drilling the Odin prospect;    Geological, geophysical and engineering studies. Unissued shares under option Testing the Nangwarry CO2 discovery; Long lead items for drilling the Cervantes prospect; and Unissued ordinary shares of Vintage under option at the date of this report are: Date options granted Holder Likely developments, business strategies and prospects Directors 13 September 2018 of shares ($) 0.35 The Company will continue to develop its existing suite of exploration assets and will work to identify other assets and corporate opportunities that will grow the Company and enhance shareholder value. 13 September 2018 Brokers 0.30 4,000,000 1,500,000 Number under option Exercise price 19 August 2019 Directors’ meetings Company Secretary 0.35 1,000,000 Total under option The number of meetings of Directors (including meetings of Committees of Directors) held during the year and the number of meetings attended by each Director is as follows: All options expire on 17 September 2021. Options do not entitle the holder to participate in any share issue of the Company. 6,500,000 Shares issued during or since the end of the year as a result of exercise of Options No options have been exercised during or since the end of the financial year. 28 Directors’ Report (continued) Rights on issue Rights to ordinary shares issued at the date of this report are: Founders (1) Managing Director (2) Management (3) Management (3) Total Date rights granted 13 September 2018 27 November 2018 13 December 2018 1 June 2019 Exercise price of shares ($) Nil Nil Nil Nil Number 7,925,646 1,875,000 1,448,000 725,000 11,973,646 Notes to the table above: (1) Founders’ Rights will vest 6 months after 30-day VWAP share price exceeds $0.30/share and otherwise expire after 3 years. (2) Details of rights held by the Managing Director are outlined in the Share Based Remuneration section below. (3) Details of rights issued to management are outlined at Note 16 in the Notes to the Financial Statements below. Environmental legislation The Company’s oil and gas operations are subject to environmental regulation under the legislation of the respective State, Territory and Federal Government jurisdictions in which it operates. Approvals, licenses, hearings and other regulatory requirements are performed by the operators of each permit or lease on behalf of joint operations in which the Company participates. The Company is potentially liable for any environmental damage from its activities, the extent of which cannot presently be quantified and would in any event be reduced by insurance carried by the Company or operator. The Company applies the oil and gas experience of its personnel to develop strategies to identify and mitigate environmental risks. Compliance by operators with environmental regulations is governed by the terms of respective joint operating agreements and is otherwise conducted using oil industry best practices. Management actively monitors compliance with regulations and as at the date of this report is not aware of any material breaches in respect of these regulations. Remuneration Report (Audited) Principles used to determine the nature and amount or remuneration The remuneration policy of Vintage has been designed to align key management personnel objectives with shareholder and business objectives by providing a fixed remuneration component and offering other incentives based on performance in achieving key objectives as approved by the Board. The Board of Vintage believes the remuneration policy to be appropriate and effective in its ability to attract and retain the best key management personnel to run and manage the Company, as well as create goal congruence between Directors, executives and shareholders. The Company’s policy for determining the nature and amounts of emoluments of Board members and other key management personnel of the Company is as follows: Remuneration and Nomination The Remuneration committee oversees remuneration matters and sets remuneration policy, fees and remuneration packages for Non-Executive Directors and senior executives. The objectives and responsibilities of the Remuneration Committee are documented in the charter approved by the Board. A copy of the charter is available on the Company’s website. The Company’s Constitution specifies that the total amount of remuneration of Non-Executive Directors shall be fixed from time to time by a general meeting. The current maximum aggregate remuneration of Non-Executive Directors has been set at $800,000 per annum. Directors may apportion any amount up to this maximum amount amongst the Non- 29 Vintage Energy Ltd Annual Report 2020 Directors’ Report (continued) Significant changes in the state of affairs Two discoveries were made during the year – natural gas at the Vali-1 ST1 well, in the ATP 2021 permit of the Cooper Executive Directors as they determine. Directors are also entitled to be paid reasonable travelling, accommodation and and Eromanga Basins, and CO2, at the Nangwarry-1 well, in the PEL 155 permit, onshore Otway Basin. other expenses incurred in performing their duties as Directors. The fees paid to Non-Executive Directors are not Both discoveries have the potential to be on production once appropriate test work and infrastructure connection is incentive or performance based but are fixed amounts that are determined by reference to the nature of the role, approved and completed. responsibility and time commitment required for the performance of the role, including membership of board committees. The Company also raised $3,000,000 ($2,250,000 from a share placement and $750,000 from a Share Purchase Plan), the funds from which were primarily used to fracture stimulate and flow test the Vali-1 ST1 gas discovery. Non-Executive Director remuneration is by way of fees and statutory superannuation contributions. Non-Executive Directors do not participate in schemes designed for remuneration of executives and are not provided with retirement Subsequent events benefits other than salary sacrifice and statutory superannuation. Fracture stimulation of the Vali-1 ST1 well over six stages was completed, with five stages in the Patchawarra Formation Executive Remuneration Policies and one in the deeper Tirrawarra Sandstone. The remuneration of the Managing Director is determined by the Remuneration committee and approved by the Board. Successful flow testing of the Vali-1 ST1 well delivered a stabilised raw gas rate, over a two-day period, of 4.3 MMscfd The terms and conditions of his employment are subject to review from time to time. through a 36/64” choke at 942 psi (flowing well-head pressure). The remuneration of other executive officers and employees is determined by the Managing Director subject to the A development concept for the Vali Field was completed and estimates a field life of around 20 years. review of the Remuneration committee. The Company’s remuneration structure is based on a number of factors including the particular experience and performance of the individual in meeting key objectives of the Company. A recoverable CO2 booking for the Nangwarry-1 discovery was made, with a gross Best Case of 25.1 Bcf recoverable CO2 estimated by ERCE. The remuneration structure and packages offered to executives are summarised below:  On 9 July 2020, the Company issued 10,694,444 shares to Directors at $0.036 per share, as part of the share capital Fixed remuneration placement announced on 30 April 2020. The shares were issued after an Extraordinary General Meeting on 29 June 2020 obtained shareholder approval for the participation of Directors in the placement. Funds for the placement had  Short-term incentive - The Company does not presently emphasise payment for results through the provision of been received prior to 30 June 2020. cash bonus schemes or other incentive payments based on key performance indicators. However, the Board may approve the payment of cash bonuses from time to time in order to reward individual executive performance in achieving key objectives as considered appropriate by the Board. On 17 September 2020, the Company announced a share placement and rights issue at $0.06 per share to raise Long-term incentive – equity grants, which may be granted annually at the discretion of the Board. From time to approximately $15,000,000. The funds raised are to be used for: time, the Company may grant retention options or rights as considered appropriate as a long-term incentive for key management personnel. Mr. Ian Northcott resigned as Alternate Director to Mr. Ian Howarth, , effective 11 August 2020.  Vali Field connection into the Moomba gathering system;  Drilling of two further Vali Field wells;  Drilling the Odin prospect;    Geological, geophysical and engineering studies. The intention of this remuneration is to facilitate the retention of key management personnel in order that the goals of the business and shareholders can be met. Under the terms of the issue of the retention rights, the rights will vest over Testing the Nangwarry CO2 discovery; a period of time, dependent upon company and individual performance. Long lead items for drilling the Cervantes prospect; and Remuneration Consultants The Company did not use any remuneration consultants during the year. Likely developments, business strategies and prospects The Company will continue to develop its existing suite of exploration assets and will work to identify other assets and Remuneration of Directors and key management personnel corporate opportunities that will grow the Company and enhance shareholder value. This report details the nature and amount of remuneration for each key management personnel of the company. Directors’ meetings Directors and key management personnel The names and positions held by Directors and key management personnel of the Company during the whole of the The number of meetings of Directors (including meetings of Committees of Directors) held during the year and the financial year are: number of meetings attended by each Director is as follows: Name Reg Nelson Neil Gibbins Nick Smart Ian Howarth Ian Northcott Simon Gray Date appointed 10 February 2017 10 February 2017 9 November 2015 9 November 2015 19 February 2018 9 November 2015 Position Chairman Managing Director Non-Executive Director Non-Executive Director Alternative Non-Executive Director Company Secretary and Chief Financial Officer 30 Directors’ Report (continued) Remuneration Summary Directors and Other Key Management Personnel 2020 Salary & fees(3) Share based remuneration Super- annuation Termination benefits Total Share based percentage of total Performance related percentage Reg Nelson 65,870 - Neil Gibbins 306,571 158,082 (1) Ian Howarth 42,497 - Nick Smart 42,497 - Ian Northcott 42,010 - Simon Gray 91,665 20,000 (2) 6,257 27,328 4,037 4,037 3,991 7,980 591,110 178,082 53,630 - - - - - - - 0% 72,127 - 491,981 32% 32% 0% 46,534 - 0% 46,534 - 0% 46,001 - 119,645 17% - 822,822 2019 Salary & fees(3) Share based remuneration Super- annuation Termination benefits Total Reg Nelson 71,000 (2) 43,500 4,132 118,632 - Neil Gibbins 289,090 (1) 289,284 26,027 604,401 - Ian Howarth 71,000 (2) 24,750 2,351 98,101 - Nick Smart 71,000 (2) 24,750 2,351 98,101 - Ian Northcott 71,000 (2) 23,288 2,212 96,500 - Simon Gray - 65,748 5,700 71,448 - 573,090 471,320 42,773 1,087,183 Share based percentage of total Performance related percentage 60% 48% 72% 72% 73% 0% - 48% - - - - Notes to the two tables above: (1) These amounts are calculated in accordance with accounting standards and represent the amortisation of accounting fair values of performance rights that have been granted to key management personnel in this or prior financial years. The fair value of performance rights have been measured using a generally accepted valuation model. The fair values are then amortised over the entire vesting period of the equity instruments. Total remuneration shown in ‘total’ therefore includes a portion of the fair value of unvested equity compensation during the year. The amount included as remuneration is not related to or indicative of the benefit (if any) that individuals may ultimately realise should these equity instruments vest and be exercised. (2) Relates to Options issued throughout the year, as outlined in the Share Based Payment section below. (3) Executive salaries include annual leave entitlements Service agreements Remuneration and other terms of employment for Executive Directors and other key management personnel are formalised in a Service agreement. Details of agreements for Executive Directors and other key management personnel is set out below: Mr. Neil Gibbins, Managing Director Base Salary $393,750 (full time equivalent) inclusive of superannuation. The position is a 0.8 full time equivalent. In the event that the Board requires Mr. Gibbins to permanently transfer to another location outside of the Adelaide Metropolitan area, Mr. Gibbins may terminate the Agreement and will be entitled to a sum equivalent of his annual salary. The Company may terminate the Agreement immediately in a number of circumstances including serious misconduct or failure to carry out the employee’s duties under the Agreement. The Company and Mr. Gibbins may also terminate the Agreement on three months’ written notice. Mr. Simon Gray, Company Secretary Base Salary $230,000 (full time equivalent) inclusive of superannuation. The position is a 0.4 full time equivalent. The agreement expires on 30 June 2021. The Agreement can be varied or extended as mutually agreed between 31 Vintage Energy Ltd Annual Report 2020 Directors’ Report (continued) Significant changes in the state of affairs Two discoveries were made during the year – natural gas at the Vali-1 ST1 well, in the ATP 2021 permit of the Cooper the parties. The agreement also provides for 1,000,000 options exercisable at $0.35 expiring on 17 September 2021. and Eromanga Basins, and CO2, at the Nangwarry-1 well, in the PEL 155 permit, onshore Otway Basin. These were issued during the year. Both discoveries have the potential to be on production once appropriate test work and infrastructure connection is approved and completed. Share based Remuneration The Company also raised $3,000,000 ($2,250,000 from a share placement and $750,000 from a Share Purchase Plan), During the year, the Company issued 1,000,000 options to Mr. Simon Gray in accordance with his employment the funds from which were primarily used to fracture stimulate and flow test the Vali-1 ST1 gas discovery. agreement which are exercisable on a one for one basis at $0.35 per share with an exercise period of up to 17 September 2021. Options carry no voting or dividend rights. The fair value on issue was $20,000. Subsequent events In the prior year, the Company issued Options to Directors on listing on the ASX which are exercisable on a one for one basis at $0.35 per share with an exercise period of up to 17 September 2021. Options carry no voting or dividend Fracture stimulation of the Vali-1 ST1 well over six stages was completed, with five stages in the Patchawarra Formation rights. and one in the deeper Tirrawarra Sandstone. Performance rights issued under the Employee Incentive Plan and to the Managing Director have been issued under Successful flow testing of the Vali-1 ST1 well delivered a stabilised raw gas rate, over a two-day period, of 4.3 MMscfd the following general performance conditions: through a 36/64” choke at 942 psi (flowing well-head pressure). Class A performance rights continued employment with the Company for 12 Months from date of commencement or A development concept for the Vali Field was completed and estimates a field life of around 20 years. date of award. A recoverable CO2 booking for the Nangwarry-1 discovery was made, with a gross Best Case of 25.1 Bcf recoverable Class B performance rights Company books a minimum 2P reserve of 1.0 MMBOE and the executive is still engaged CO2 estimated by ERCE. as an employee three years after commencing employment with the company. On 9 July 2020, the Company issued 10,694,444 shares to Directors at $0.036 per share, as part of the share capital Class C performance rights at any stage prior to the end three years after signing the employment agreement the placement announced on 30 April 2020. The shares were issued after an Extraordinary General Meeting on 29 June Company’s share price (30-day VWAP) reaching a share price (variable in each issue of rights) and still being engaged 2020 obtained shareholder approval for the participation of Directors in the placement. Funds for the placement had as an executive at the end of the three years. been received prior to 30 June 2020. Performance rights issued to Mr. Neil Gibbins pursuant to the resolution at the 27 November 2018 Annual General Mr. Ian Northcott resigned as Alternate Director to Mr. Ian Howarth, , effective 11 August 2020. Meeting. On 17 September 2020, the Company announced a share placement and rights issue at $0.06 per share to raise Performance rights at the date of this report are: approximately $15,000,000. The funds raised are to be used for: Class of Performance Rights  Vali Field connection into the Moomba gathering system;  Drilling of two further Vali Field wells;  Drilling the Odin prospect;  Class B Performance Rights   Geological, geophysical and engineering studies. Testing the Nangwarry CO2 discovery; Long lead items for drilling the Cervantes prospect; and Maximum Number of Performance Rights 937,500 Performance Condition At any stage prior to 1 March 2021 the Company books a minimum proven and probable (2P) reserve of 1.0 million barrels oil equivalent (MMBOE) and Mr. Gibbins is still engaged as an employee at 1 March 2021. Likely developments, business strategies and prospects 937,500 Class C Performance Rights The Company will continue to develop its existing suite of exploration assets and will work to identify other assets and corporate opportunities that will grow the Company and enhance shareholder value. At any stage prior to 1 March 2021 the Company’s share price (30-day volume weighted average price (VWAP)) reaching $0.50 per share, and Mr. Gibbins is still engaged as an employee at 1 March 2021. Total Directors’ meetings 1,875,000 The number of meetings of Directors (including meetings of Committees of Directors) held during the year and the Performance rights convert to ordinary shares on the completion of the performance conditions. number of meetings attended by each Director is as follows: Performance rights carry no dividends or voting rights and when exercisable each right is converted into one ordinary share. They are excisable at nil value. Details of performance rights and options granted over ordinary shares that were granted as remuneration to each key management personnel are set out below: Employee Class Number of rights granted Grant Date Value at Grant date Number converted Last date Neil Gibbins Neil Gibbins B C 937,500 27 November 2018 196,875 937,500 27 November 2018 158,812 - - 1 March 2021 1 March 2021 32 Directors’ Report (continued) Directors and other key management personnel equity remuneration, holdings and transactions The number of shares in the Company held during the financial year by each Director and other key management personnel of the Company, including their personal related parties, are set out below: Name Reg Nelson Neil Gibbins Ian Howarth Nick Smart Ian Northcott Simon Gray Balance 1 July 2019 9,161,177 8,588,677 8,661,177 5,911,177 5,911,177 5,911,177 Converted rights Options Exercised - - - - - - - - - - - - Net Change Other 250,186 (i) 250,186 (i) - 166,790 (i) Balance 9,411,363 8,838,863 8,661,177 6,077,967 - 5,911,177 83,395 (i) 5,994,572 Notes to the table above: (i) Shares were acquired during the year as part of the capital raise announced on 30 April 2020. The number of Options held during the financial year by each Director and other key management personnel of the Company, including their personal related parties are detailed below: Name Reg Nelson Neil Gibbins Ian Howarth Nick Smart Ian Northcott Simon Gray Balance 1 July 2019 1,000,000 - 1,000,000 1,000,000 1,000,000 - Options granted - - - - - 1,000,000 Options Exercised Balance - - - - - - 1,000,000 - 1,000,000 1,000,000 1,000,000 1,000,000 The number of Rights held during the financial year by each Director and other key management personnel of the Company, including their personal related parties are detailed below: Name Reg Nelson Neil Gibbins Ian Howarth Nick Smart Ian Northcott Simon Gray Balance 1 July 2019 Rights converted Rights lapsed Balance Rights Founders 1,320,941 3,195,941 1320,941 1,320,941 1,320,941 1,320,941 - - - - - - - - - - - - 1,320,941 1,320,941 (i) 3,195,941 1,320,941 (i) 1,320,941 1,320,941 (i) 1,320,941 1,320,941 (i) 1,320,941 1,320,941 (i) 1,320,941 1,320,941 (i) Notes to the table above: (i) Founders rights vest 6 months after the 30 day VWOP exceeds $0.30 per share and otherwise expire 3 years after issue, on 17 September 2021. Shares issued on exercise of remuneration options No shares were issued to Directors or key management as a result of the exercise of options during the financial year. Employee Incentive Plan The shareholders of the Company approved an Employee Incentive Plan for employees at the Annual General Meeting held on 27 November 2018. Performance rights issued pursuant to the Plan to eligible employees other than Directors and key management personnel as at 30 June 2020 is detailed at Note 16 to the Financial Statements below. 33 Vintage Energy Ltd Annual Report 2020 Directors’ Report (continued) Significant changes in the state of affairs Two discoveries were made during the year – natural gas at the Vali-1 ST1 well, in the ATP 2021 permit of the Cooper Transactions with key management personnel and Eromanga Basins, and CO2, at the Nangwarry-1 well, in the PEL 155 permit, onshore Otway Basin. An affiliate of the Managing Director is employed with the Company in a technical exploration position, with Both discoveries have the potential to be on production once appropriate test work and infrastructure connection is remuneration based on an arm’s length review and at a rate consistent with the position filled. The Managing Director approved and completed. has no role in the determination of salary or benefits paid to the employee. Other than the above, there were no other The Company also raised $3,000,000 ($2,250,000 from a share placement and $750,000 from a Share Purchase Plan), transactions with other key management personnel. the funds from which were primarily used to fracture stimulate and flow test the Vali-1 ST1 gas discovery. END OF REMUNERATION REPORT Subsequent events Indemnities given to, and insurance premiums paid for, auditors and Fracture stimulation of the Vali-1 ST1 well over six stages was completed, with five stages in the Patchawarra Formation officers and one in the deeper Tirrawarra Sandstone. Insurance of officers Successful flow testing of the Vali-1 ST1 well delivered a stabilised raw gas rate, over a two-day period, of 4.3 MMscfd through a 36/64” choke at 942 psi (flowing well-head pressure). During the year, Vintage paid a premium to insure officers of the Company. The officers covered by insurance include all Directors and Officers. A development concept for the Vali Field was completed and estimates a field life of around 20 years. The liabilities insured are legal costs that may be incurred in defending civil or criminal proceedings that may be bought A recoverable CO2 booking for the Nangwarry-1 discovery was made, with a gross Best Case of 25.1 Bcf recoverable against the officers in their capacity as officers of the Company, and any other payments arising from liabilities incurred CO2 estimated by ERCE. by the officers in connection with such proceedings, other than where such liabilities arise out of conduct involving a On 9 July 2020, the Company issued 10,694,444 shares to Directors at $0.036 per share, as part of the share capital willful breach of duty by the officers or the improper use by the officers of their position or of information to gain placement announced on 30 April 2020. The shares were issued after an Extraordinary General Meeting on 29 June advantage for themselves or someone else to cause detriment to the Company. 2020 obtained shareholder approval for the participation of Directors in the placement. Funds for the placement had Details of the amount of premium paid in respect of insurance policies are not disclosed, as their disclosure is prohibited been received prior to 30 June 2020. under the terms of the contract. Mr. Ian Northcott resigned as Alternate Director to Mr. Ian Howarth, , effective 11 August 2020. The Company has not otherwise, during or since the end of the financial year, except to the extent permitted by law, On 17 September 2020, the Company announced a share placement and rights issue at $0.06 per share to raise indemnified or agreed to indemnify any current or former officer of the Company against a liability incurred as such by approximately $15,000,000. The funds raised are to be used for: an officer. Indemnity of auditors  Vali Field connection into the Moomba gathering system;  Drilling of two further Vali Field wells;  Drilling the Odin prospect;    Geological, geophysical and engineering studies. The Company has agreed to indemnify its auditors, Grant Thornton Audit Pty Ltd, to the extent permitted by law, against any claim by a third party arising from the Company’s breach of its agreement. The indemnity requires the Company to meet the full amount of any such liabilities including a reasonable amount of legal costs. Testing the Nangwarry CO2 discovery; Long lead items for drilling the Cervantes prospect; and Proceedings of behalf of the Company Likely developments, business strategies and prospects No person has applied to the Court under section 237 of the Corporations Act 2001 for leave to bring proceedings on The Company will continue to develop its existing suite of exploration assets and will work to identify other assets and behalf of the Company, or to intervene in any proceedings to which the Company is a party, for the purpose of taking corporate opportunities that will grow the Company and enhance shareholder value. responsibility on behalf of the Company for all or part of those proceedings. Directors’ meetings Non-audit services The number of meetings of Directors (including meetings of Committees of Directors) held during the year and the During the year, Grant Thornton Audit Pty Ltd, the Company’s auditors, performed certain other services in addition to number of meetings attended by each Director is as follows: their statutory audit duties. The Board has considered the non-audit services provided during the year by the auditor and is satisfied that the provision of those non-audit services during the year is compatible with, and did not compromise, the auditor independence requirements of the Corporations Act 2001 for the following reasons:   all non-audit services were subject to the corporate governance procedures adopted by the Company and have been reviewed by the Directors to ensure they do not impact upon the impartiality and objectivity of the auditor. the non-audit services do not undermine the general principles relating to auditor independence as set out in APES 110 Code of Ethics for Professional Accountants, as they did not involve reviewing or auditing the auditor’s own work, acting in a management or decision-making capacity for the Company, acting as an advocate for the Company or jointly sharing risks and rewards. Details of the amounts paid to the auditors of the Company, Grant Thornton Audit Pty Ltd, and its related practices for audit and non-audit services provided during the year are set out in Note 23 to the financial statements. 34 A copy of the Auditor’s Independence Declaration as required under s.307C of the Corporations Act 2001 is included on the next page of this financial report and forms part of this Directors’ Report. Signed in accordance with a resolution of the Directors. Reg Nelson Chairman 30 September 2020 35 Vintage Energy Ltd Annual Report 2020 Auditor’s Independence Declaration Auditor’s Independence Declaration To the Directors of Vintage Energy Limited Level 3, 170 Frome Street Adelaide SA 5000 Correspondence to: GPO Box 1270 Adelaide SA 5001 T +61 8 8372 6666 Level 3, 170 Frome Street Adelaide SA 5000 Correspondence to: GPO Box 1270 Adelaide SA 5001 T +61 8 8372 6666 In accordance with the requirements of section 307C of the Corporations Act 2001, as lead auditor for the audit of Vintage Energy Limited for the year ended 30 June 2020, 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. Auditor’s Independence Declaration To the Directors of Vintage Energy Limited GRANT THORNTON AUDIT PTY LTD In accordance with the requirements of section 307C of the Corporations Act 2001, as lead auditor for the audit of Vintage Chartered Accountants Energy Limited for the year ended 30 June 2020, 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. J L Humphrey Partner – Audit & Assurance Adelaide, 30 September 2020 GRANT THORNTON AUDIT PTY LTD Chartered Accountants J L Humphrey Partner – Audit & Assurance Adelaide, 30 September 2020 Grant Thornton Audit Pty Ltd ACN 130 913 594 a subsidiary or related entity of Grant Thornton Australia Ltd ABN 41 127 556 389 www.grantthornton.com.au ‘Grant Thornton’ refers to the brand under which the Grant Thornton member firms provide assurance, tax and advisory services to their clients and/or refers to one or more member firms, as the context requires. Grant Thornton Australia Ltd is a member firm of Grant Thornton International Ltd (GTIL). GTIL and the member firms are not a worldwide partnership. GTIL and each member firm is a separate legal entity. Services are delivered by the member firms. GTIL does not provide services to clients. GTIL and its member firms are not agents of, and do not obligate one another and are not liable for one another’s acts or omissions. In the Australian context only, the use of the term ‘Grant Thornton’ may refer to Grant Thornton Australia Limited ABN 41 127 556 389 and its Australian subsidiaries and related entities. GTIL is not an Australian related entity to Grant Thornton Australia Limited. Liability limited by a scheme approved under Professional Standards Legislation. 36 Grant Thornton Audit Pty Ltd ACN 130 913 594 a subsidiary or related entity of Grant Thornton Australia Ltd ABN 41 127 556 389 www.grantthornton.com.au ‘Grant Thornton’ refers to the brand under which the Grant Thornton member firms provide assurance, tax and advisory services to their clients and/or refers to one or more member firms, as the context requires. Grant Thornton Australia Ltd is a member firm of Grant Thornton International Ltd (GTIL). GTIL and the member firms are not a worldwide partnership. GTIL and each member firm is a separate legal entity. Services are delivered by the member firms. GTIL does not provide services to clients. GTIL and its member firms are not agents of, and do not obligate one another and are not liable for one another’s acts or omissions. In the Australian context only, the use of the term ‘Grant Thornton’ may refer to Grant Thornton Australia Limited ABN 41 127 556 389 and its Australian subsidiaries and related entities. GTIL is not an Australian related entity to Grant Thornton Australia Limited. Liability limited by a scheme approved under Professional Standards Legislation. Corporate Governance Statement The Board is committed to achieving and demonstrating the highest standards of corporate governance. As such, the Company has adopted the third edition of the Corporate Governance Principles and Recommendations which was released by the ASX Corporate Governance Council on 27 March 2014 and became effective for financial years beginning on or after 1 July 2014. The Company’s Corporate Governance Statement for the financial year ending 30 June 2020 is dated as at 30 September 2020 and was approved by the Board on 30 September 2020. The Corporate Governance Statement is available on Vintage’s website at https://www.vintageenergy.com.au/governance-policies.html Grant Thornton Audit Pty Ltd ACN 130 913 594 a subsidiary or related entity of Grant Thornton Australia Ltd ABN 41 127 556 389 www.grantthornton.com.au 37 Level 3, 170 Frome Street Adelaide SA 5000 Correspondence to: GPO Box 1270 Adelaide SA 5001 T +61 8 8372 6666 Level 3, 170 Frome Street Adelaide SA 5000 Correspondence to: GPO Box 1270 Adelaide SA 5001 T +61 8 8372 6666 Auditor’s Independence Declaration To the Directors of Vintage Energy Limited In accordance with the requirements of section 307C of the Corporations Act 2001, as lead auditor for the audit of Vintage Energy Limited for the year ended 30 June 2020, 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. Auditor’s Independence Declaration To the Directors of Vintage Energy Limited GRANT THORNTON AUDIT PTY LTD Chartered Accountants In accordance with the requirements of section 307C of the Corporations Act 2001, as lead auditor for the audit of Vintage Energy Limited for the year ended 30 June 2020, 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. J L Humphrey Partner – Audit & Assurance Adelaide, 30 September 2020 GRANT THORNTON AUDIT PTY LTD Chartered Accountants J L Humphrey Partner – Audit & Assurance Adelaide, 30 September 2020 Grant Thornton Audit Pty Ltd ACN 130 913 594 a subsidiary or related entity of Grant Thornton Australia Ltd ABN 41 127 556 389 www.grantthornton.com.au ‘Grant Thornton’ refers to the brand under which the Grant Thornton member firms provide assurance, tax and advisory services to their clients and/or refers to one or more member firms, as the context requires. Grant Thornton Australia Ltd is a member firm of Grant Thornton International Ltd (GTIL). GTIL and the member firms are not a worldwide partnership. GTIL and each member firm is a separate legal entity. Services are delivered by the member firms. GTIL does not provide services to clients. GTIL and its member firms are not agents of, and do not obligate one another and are not liable for one another’s acts or omissions. In the Australian context only, the use of the term ‘Grant Thornton’ may refer to Grant Thornton Australia Limited ABN 41 127 556 389 and its Australian subsidiaries and related entities. GTIL is not an Australian related entity to Grant Thornton Australia Limited. Liability limited by a scheme approved under Professional Standards Legislation. ‘Grant Thornton’ refers to the brand under which the Grant Thornton member firms provide assurance, tax and advisory services to their clients and/or refers to one or more member firms, as the context requires. Grant Thornton Australia Ltd is a member firm of Grant Thornton International Ltd (GTIL). GTIL and the member firms are not a worldwide partnership. GTIL and each member firm is a separate legal entity. Services are delivered by the member firms. GTIL does not provide services to clients. GTIL and its member firms are not agents of, and do not obligate one another and are not liable for one another’s acts or omissions. In the Australian context only, the use of the term ‘Grant Thornton’ may refer to Grant Thornton Australia Limited ABN 41 127 556 389 and its Australian subsidiaries and related entities. GTIL is not an Australian related entity to Grant Thornton Australia Limited. Liability limited by a scheme approved under Professional Standards Legislation. Vintage Energy Ltd Annual Report 2020 Statement of Profit or Loss and Other Comprehensive Income For year ended 30 June 2020 Interest income Joint Venture recoveries Other income Depreciation expense Exploration expense Key management personnel option expense Initial Public Offer costs Employee benefits expense Other expenses (Loss) before income tax Income tax benefit (Loss) for the year Other comprehensive income Total comprehensive income (loss) attributable to owners of the company for the year Notes 30 June 2020 $ 105,888 1,279,738 35,979 (190,648) (54,200) (20,000) - 30 June 2019 $ 367,305 - - (44,834) (40,878) (284,000) (429,440) 5 5 6 (2,333,939) (1,742,617) (1,028,666) (1,248,322) (2,205,848) (3,422,786) - - (2,205,848) (3,422,786) - - (2,205,848) (3,422,786) Earnings per share Basic (loss) per share from continuing operations (cents) Diluted (loss) per share from continuing operations (cents) 18 18 (0.0079) (0.0079) (0.0157) (0.0160) This statement should be read in conjunction with the notes to the financial statements. 38 Statement of Financial Position As at 30 June 2020 Current Asset Cash and cash equivalents Trade and other receivables Total current assets Non-Current Assets Property, plant and equipment Exploration and evaluation assets Total non-current assets Total Assets Current Liabilities Trade and other payables Deferred grant income Provisions Other financial liabilities Total current liabilities Non-Current Liabilities Provisions Total non-current liabilities Total Liabilities Net Assets/(Liabilities) Equity Share capital Reserves Accumulated (losses) Total Equity / (Deficit) Notes 30 June 2020 $ 30 June 2019 $ 7 8 9 10 11 12 13 14 13 3,443,239 22,296,212 378,307 125,372 3,821,546 22,421,584 169,539 150,384 28,942,270 12,149,492 29,111,809 12,299,876 32,933,355 34,721,460 163,332 - 198,539 320,380 682,251 482,726 2,475,000 98,404 - 3,056,130 925,000 925,000 925,000 925,000 1,607,251 3,981,130 31,326,104 30,740,330 15 36,891,576 34,392,805 867,181 574,330 (6,432,653) (4,226,805) 31,326,104 30,740,330 This statement should be read in conjunction with the notes to the financial statement 39 Vintage Energy Ltd Annual Report 2020 Statement of Changes in Equity For the year ended 30 June 2020 Note s Share capital Accumulated losses Share based payments reserve Total equity / (deficit) $ $ $ Balance at 1 July 2018 6,164,409 (804,019) (Loss) for the year Other comprehensive income Total comprehensive (loss) for the year Total transactions with owners Issue of ordinary shares at $0.20 – IPO Issue of ordinary shares on conversion of rights Fair value of share options issued Fair value of performance rights issued Transaction costs Balance at 30 June 2019 - - - (3,422,786) - (3,422,786) 15 15 30,000,000 436,125 - - 15 (2,207,729) - - - - - - - - - (436,125) 402,451 608,004 5,360,390 (3,422,786) - (3,422,786) 30,000,000 - 402,451 608,004 - (2,207,729) 34,392,805 (4,226,805) 574,330 30,740,330 Balance at 1 July 2019 34,392,805 (4,226,805) 574,330 30,740,330 (Loss) for the year Other comprehensive income Total comprehensive (loss) for the year Total transactions with owners Issue of ordinary shares at $0.036 Issue of ordinary shares on conversion of rights Issue of ordinary shares as share-based payments Fair value of share options issued Fair value of performance rights issued Transaction costs Balance at 30 June 2020 - - - (2,205,848) - (2,205,848) 15 15 15 2,615,000 87,000 2,334 - - 15 (205,563) - - - - - - - - - - (87,000) - 20,000 359,851 (2,205,848) - (2,205,848) 2,615,000 - 2,334 20,000 359,851 - (205,563) 36,891,576 (6,432,653) 867,181 31,326,104 This statement should be read in conjunction with the notes to the financial statement 40 Statement of Cash Flows For the year ended 30 June 2020 CASH FLOWS FROM OPERATING ACTIVITIES Payments to suppliers and employees Payments for exploration and evaluation – expensed Interest and other income Net cash (used in) operating activities CASH FLOWS FROM INVESTING ACTIVITIES Payments for exploration and evaluation Payments for property, plant and equipment Cash flows (used in) investing activities CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from issues of shares Payment for share issue costs Payment of the principal portion of lease liabilities Net cash from financing activities Notes 30 June 2020 $ 30 June 2019 $ (3,446,993) (2,787,937) (54,199) 139,214 (40,879) 367,305 24 (3,361,978) (2,461,511) (18,007,305) (8,165,832) (3,450) (124,904) (18,010,755) (8,290,736) 2,854,000 30,000,000 (206,563) (127,677) (1,902,325) - 2,519,760 28,097,675 Net change in cash and cash equivalents (18,852,973) 17,345,428 Cash and cash equivalents at the beginning of year Cash and cash equivalents at end of year 22,296,212 4,950,784 7 3,443,239 22,296,212 This statement should be read in conjunction with the notes to the financial statement 41 Vintage Energy Ltd Annual Report 2020 Notes to the Financial Statements 1 Nature of Operations Vintage is an Australian listed public company, incorporated in Australia and operating in Australia. The principal activities of the Company are disclosed in the Directors’ Report. Vintage’s registered office and its principal place of business at the date of this report is 58 King William Road, Goodwood SA 5034. 2 General information and statement of compliance The general-purpose financial statements of the Company have been prepared in accordance with the requirements of the Corporations Act 2001, Australian Accounting Standards and other authoritative pronouncements of the Australian Accounting Standards Board (AASB). Compliance with Australian Accounting Standards results in full compliance with the International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB). Vintage Energy Limited is a for-profit entity for the purpose of preparing the financial statements. The financial statements for the year ended 30 June 2020 were approved and authorised for issue by the Board of Directors on 30 September 2020. 3 Changes in accounting policies 3.1 New and revised standards that are effective for these financial statements AASB 16 Leases AASB 16 supersedes AASB 117 Leases, Interpretation 4 Determining whether an Arrangement contains a Lease, Interpretation 115 Operating Leases-Incentives and Interpretation 127 Evaluating the Substance of Transactions Involving the Legal Form of a Lease. The standard sets out the principles for the recognition, measurement, presentation and disclosure of leases and requires lessees to account for most leases under a single on-balance sheet model. Lessor accounting under AASB 16 is substantially unchanged from AASB 117. Lessors will continue to classify leases as either operating or finance leases using similar principles as in AASB 117. Therefore, AASB 16 did not have an impact for leases where the Company is the lessor. The Company adopted AASB 16 using the modified retrospective method of adoption with the date of initial application of 1 July 2019. Under this method, the standard is applied retrospectively with the cumulative effect of initially applying the standard recognised at the date of initial application. The Company elected to use the transition practical expedient allowing the standard to be applied only to contracts that were previously identified as leases applying AASB 117 and Interpretation 4 at the date of initial application. The Company has considered applying exemptions for lease contracts that, at the commencement date, have a lease term of 12 months or less and do not contain a purchase option (‘short- term leases’), and lease contracts for which the underlying asset is of low value (‘low-value assets’). The following is a reconciliation of total operating lease commitments at 30 June 2019 to the lease liabilities recognised at 1 July 2019: Total operating lease commitments disclosed as at 30 June 2019 Discounted using incremental borrowing rate Total lease liabilities recognised under AASB 16 at 1 July 2019 $ 249,000 (42,647) 206,353 42 The effect of adopting AASB 16 as at 1 July 2019 Assets Right of use assets Liabilities Other financial liabilities current Other financial liabilities non-current Total liabilities $ 206,353 123,584 82,769 206,353 (a) Nature of the effect of adoption of AASB 16 The Company has lease contracts for office premises. Before the adoption of AASB 16, the Company classified each of its leases (as lessee) at the inception date as either a finance lease or an operating lease. A lease was classified as a finance lease if it transferred substantially all of the risks and rewards incidental to ownership of the leased asset to the Company; otherwise it was classified as an operating lease. Finance leases were capitalised at the commencement of the lease at the inception date fair value of the leased property or, if lower, at the present value of the minimum lease payments. Lease payments were apportioned between interest (recognised as finance costs) and reduction of the lease liability. In an operating lease, the leased property was not capitalised, and the lease payments were recognised as rent expense in profit or loss on a straight-line basis over the lease term. Any prepaid rent and accrued rent were recognised under Prepayments and Trade and other payables, respectively. Upon adoption of AASB 16, the Company applied a single recognition and measurement approach for all leases. The standard provides specific transition requirements and practical expedients, which has been applied by the Company. (b) Leases previously accounted for as operating leases The Company recognised right-of-use assets and lease liabilities for those leases previously classified as operating leases, except for short-term leases and leases of low-value assets. The right-of-use assets for most leases were recognised based on the carrying amount as if the standard had always been applied, apart from the use of incremental borrowing rate at the date of initial application. In some leases, the right-of-use assets were recognised based on the amount equal to the lease liabilities, adjusted for any related prepaid and accrued lease payments previously recognised. Lease liabilities were recognised based on the present value of the remaining lease payments, discounted using the incremental borrowing rate at the date of initial application. The Company also applied the available practical expedients wherein it: • Used a single discount rate of 5% to a portfolio of leases with reasonably similar characteristics; • Relied on its assessment of whether leases are onerous immediately before the date of initial application; • Excluded the initial direct costs from the measurement of the right-of-use asset at the date of initial application; and • Used hindsight in determining the lease term where the contract contains options to extend or terminate the lease. Based on the foregoing, as at 1 July 2019: • Right-of-use assets of $206,353 were recognised as property, plant and equipment in the Statement of Financial Position; • Additional lease liabilities of $206,353 (included in Other financial liabilities) were recognised. (c) Summary of new accounting policies The adoption of AASB 16 has not had a significant impact on the Company's financial results. During the year, the Company recognised $123,812 depreciation in relation to the right-of-use asset, per Note 9, as well as interest expense of $2,472. These expenses were offset by a reduction in other expenses (reclassification of rental expenses) of $127,677. AASB Interpretation 23 Uncertainty over Income Tax Treatment The Interpretation addresses the accounting for income taxes when tax treatments involve uncertainty that affects the application of AASB 112 Income Taxes. It does not apply to taxes or levies outside the scope of AASB 12, nor does it specifically include requirements relating to interest and penalties associated with uncertain tax treatments. The Interpretation specifically addresses the following: 43 Vintage Energy Ltd Annual Report 2020  Whether an entity considers uncertain tax treatments separately    The assumptions an entity makes about the examination of tax treatments by taxation authorities How an entity determines taxable profit (tax loss), tax bases, unused tax losses, unused tax credits and tax rates How an entity considers changes in facts and circumstances An entity has to determine whether to consider each uncertain tax treatment separately or together with one or more other uncertain tax treatments. The approach that better predicts the resolution of the uncertainty needs to be followed. The Company applies significant judgement in identifying uncertainties over income tax treatments. Since the Company operates in a complex multinational environment, it assessed whether the Interpretation had an impact on its consolidated financial statements. Upon adoption of the Interpretation, the Company considered whether it had any uncertain tax positions. The interpretation did not have an impact on the consolidated financial statements of the Company. 4 Summary of accounting policies 4.1 Overall considerations The financial statements have been prepared using the significant accounting policies and measurement bases summarised below. 4.2 Basis of preparation The financial statements have been prepared on the basis of historical cost except, where applicable, for the revaluation of certain non-current assets and financial instruments. All amounts are presented in Australian dollars, unless otherwise noted. The following significant accounting policies have been adopted in the preparation and presentation of the financial report. 4.3 Cash and cash equivalents Cash and cash equivalents include cash on hand, deposits held at call with financial institutions and 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 on value, net of outstanding bank overdrafts. Income taxes 4.4 Tax expense recognised in profit or loss comprises the sum of deferred tax and current tax not recognised in other comprehensive income or directly in equity. Current income tax assets and/or liabilities comprise those obligations to, or claims from, the Australian Taxation Office (ATO) and other fiscal authorities relating to the current or prior reporting periods that are unpaid at the reporting date. Current tax is payable on taxable profit, which differs from profit or loss in the financial statements. Calculation of current tax is based on tax rates and tax laws that have been enacted or substantively enacted by the end of the reporting period. Deferred income taxes are calculated using the liability method on temporary differences between the carrying amounts of assets and liabilities and their tax bases. However, deferred tax is not provided on the initial recognition of goodwill or on the initial recognition of an asset or liability unless the related transaction is a business combination or affects tax or accounting profit. Deferred tax on temporary differences associated with investments in subsidiaries and joint ventures is not provided if reversal of these temporary differences can be controlled by the Company and it is probable that reversal will not occur in the foreseeable future. Deferred tax assets and liabilities are calculated, without discounting, at tax rates that are expected to apply to their respective period of realisation, provided they are enacted or substantively enacted by the end of the reporting period. Deferred tax assets are recognised to the extent that it is probable that they will be able to be utilised against future taxable income, based on the Company’s forecast of future operating results which is adjusted for significant non-taxable income and expenses and specific limits to the use of any unused tax loss or credit. Deferred tax liabilities are always provided for in full. Deferred tax assets and liabilities are offset only when the Company has a right and intention to set off current tax assets and liabilities from the same taxation authority. Changes in deferred tax assets or liabilities are recognised as a component of tax income or expense in profit or loss, except where they relate to items that are recognised in other comprehensive income (such as the revaluation of land) or 44 directly in equity, in which case the related deferred tax is also recognised in other comprehensive income or equity, respectively. 4.5 Provisions Provisions are recognised when the Company has a present obligation as a result of a past event, the future sacrifice of economic benefits is probable, and the amount of the provision can be measured reliably. The amount recognised as a provision is the best estimate of the consideration required to settle the present obligation at reporting date, taking into account the risks and uncertainties surrounding the obligation. Where a provision is measured using the cash flows estimated to settle the present obligation, its carrying amount is the present value of those cash flows. When some or all of the economic benefits required to settle a provision are expected to be recovered from a third party, the receivable is recognised as an asset if it is virtually certain that recovery will be received and the amount of the receivable can be measured reliably. 4.6 Estimate of restoration costs The Company estimates the future removal costs of wells and pipelines at different stages of the development and construction of assets or facilities. In most instances, removal of assets occurs many years into the future. This requires judgemental assumptions regarding removal date, future environmental legislation, the extent of reclamation activities required, the engineering methodology for estimating cost, future removal technologies in determining the removal cost, and liability specific discount rates to determine the present value of these cash flows. The provision amount represents the Company’s current best estimate of its restoration obligations to be performed in the future based on current industry practice and expectations. However, this will be dependent on approval by regulatory authorities prior to restoration activities being undertaken and may be subject to change. 4.7 Employee Benefits Provision is made for the Company’s liability for employee benefits arising from services rendered by employees to reporting date. Employee benefits that are expected to be settled within one year have been measured at the amounts expected to be paid when the liability is settled, plus related on-costs. Employee benefits payable later than one year have been measured at the present value of the estimated future cash outflows to be made for those benefits. Those cash flows are discounted using high quality corporate bonds with terms to maturity that match the expected timing of cash flows. 4.8 Trade and other Payables These amounts represent liabilities for goods and services provided to the Company prior to the end of the financial year which are unpaid. The amounts are unsecured and are usually paid according to term. 4.9 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. Assets and liabilities measured at fair value are classified, into three levels, using a fair value hierarchy that reflects the significance of the inputs used in making the measurements. Classifications are reviewed at each reporting date and transfers between levels are determined based on a reassessment of the lowest level of input that is significant to the fair value measurement, which are described as follows:    Level 1 - inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the entity can access at the measurement date; Level 2 - inputs are inputs, other than quoted prices included in Level 1, that are observable for the asset or liability, either directly or indirectly; and Level 3 - inputs are unobservable inputs for the asset or liability 45 Vintage Energy Ltd Annual Report 2020 For recurring and non-recurring fair value measurements, external valuers may be used when internal expertise is either not available or when the valuation is deemed to be significant. External valuers are selected based on market knowledge and reputation. Where there is a significant change in fair value of an asset or liability from one period to another, an analysis is undertaken, which includes a verification of the major inputs applied in the last valuation and a comparison, where applicable, with external sources of data. 4.10 Goods and Services Tax (GST) Revenues, expenses and assets are recognised net of the amount of GST, except where the amount of GST incurred is not recoverable from the Local Taxation Office. In these circumstances, the GST is recognised as part of the cost of acquisition of the asset or as part of an item of the expense. Receivables and payables in the Statement of Financial Position are shown inclusive of GST. Cash flows are presented in the Statement of Cash Flows on a gross basis, except for the GST component of investing and financing activities, which are disclosed as operating cash flows. 4.11 Property, plant and equipment Plant and equipment are stated at cost less accumulated depreciation and impairment. Cost includes expenditure that is directly attributable to the acquisition of the item. Subsequent costs are included in the asset’s carrying amount or recognised as a separate asset, as appropriate, only when it is probable that future economic benefits associated with the item will flow to the Company and the cost of the item can be measured reliably. All other repairs and maintenance are charged to the Statement of Profit or Loss and other comprehensive income during the financial period in which they are incurred. All tangible assets have limited useful lives and are depreciated using the straight-line value method over their estimated useful lives, taking into account estimated residual values, to write off the cost to its estimated residual value, as follows: – Furniture and fittings: 20% – Plant and equipment: 33% Leasehold improvements are depreciated over the period of the lease or estimated useful life, whichever is the shorter, using the straight-line method. The estimated useful lives, residual values and depreciation method are reviewed at the end of each annual reporting period and adjusted if appropriate. 4.12 Impairment of assets At each reporting date the Company reviews the carrying amounts of its assets to determine whether there is any indication that those assets have suffered an impairment loss. If any such indication exists, the recoverable amount of the asset is estimated in order to determine the extent of the impairment loss (if any). Where the asset does not generate cash flows that are independent from other assets, the Company estimates the recoverable amount of the cash-generating unit to which the asset belongs. Where a reasonable and consistent basis of allocation can be identified, corporate assets are also allocated to individual cash-generating units or otherwise they are allocated to the smallest group of cash-generating units for which a reasonable and consistent allocation basis can be identified. 4.13 Exploration and evaluation costs Exploration and evaluation expenditure includes costs incurred in the search for hydrocarbon resources and determining its commercial viability in each identifiable area of interest. Exploration and evaluation expenditure is accounted for in accordance with the successful efforts method and is capitalised to the extent that: i. ii. iii. the rights to tenure of the areas of interest are current and the Company controls the area of interest in which the expenditure has been incurred; and such costs are expected to be recouped through successful development and exploration of the area of interest, or alternatively by its sale; or 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. An area of interest refers to an individual geological area where the potential presence of an oil or a natural gas field is considered favourable or has been proven to exist, and in most cases, will comprise an individual prospective oil or gas field. Exploration and evaluation expenditure which does not satisfy these criteria is written off. 46 Specifically, costs carried forward in respect of an area of interest that is abandoned or costs relating directly to the drilling of an unsuccessful well are written off in the year in which the decision to abandon is made or the results of drilling are concluded. The success or otherwise of a well is determined by reference to the drilling objectives for that well. For successful wells, the well costs remain capitalised on the Statement of Financial Position as long as sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. A regular review is undertaken of each area of interest to determine the appropriateness of continuing to carry forward costs in relation to that area of interest. Where an ownership interest in an exploration and evaluation asset is exchanged for another, the transaction is recognised by reference to the carrying value of the original interest. Any cash consideration paid, including transaction costs, is accounted for as an acquisition of exploration and evaluation assets. Any cash consideration received, net of transaction costs, is treated as a recoupment of costs previously capitalised with any excess accounted for as a gain on disposal of non-current assets. Where a discovered oil or gas field enters the development phase the accumulated exploration and evaluation expenditure is transferred to oil and gas assets. 4.14 Interest in joint operations A joint operation is a joint arrangement whereby the parties that have joint control of the arrangement have rights to the assets, and obligations for the liabilities, relating to the arrangement. Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control. Under certain agreements, more than one combination of participants can make decisions about the relevant activities and therefore joint control does not exist. Where the arrangement has the same legal form as a joint operation but is not subject to joint control, the Company accounts for its interest in accordance with the contractual agreement by recognising its share of jointly held assets, liabilities, revenues and expenses of the arrangement. When the Company undertakes its activities under joint operations, the Company as a joint operator recognises in relation to its interest in a joint operation:       Its assets, including its share of any assets jointly held; Its liabilities, including its share of any liabilities incurred jointly; Its revenue from the sale of its share of the output arising from the joint operation; Its revenue from salary recoveries and overhead charges; Its share of the revenue from the sale of the output by the joint operation; and Its expenses, including its share of any expenses incurred jointly. The Company accounts for its assets, liabilities, revenues and expenses relating to its interest in a joint operation in accordance with the AASBs applicable to the particular assets, liabilities, revenues and expenses. 4.15 Financial instruments Recognition, initial measurement and derecognition Financial instruments, incorporating financial assets and financial liabilities, are recognised when the entity becomes a party to the contractual provisions of the instrument. Trade date accounting is adopted for financial assets that are delivered within timeframes established by marketplace convention. Financial instruments are initially measured at fair value plus transactions costs where the instrument is not classified as at fair value through profit or loss. Transaction costs related to instruments classified as at fair value through profit or loss are expensed to profit or loss immediately. Financial assets are derecognised when the contractual rights to the cash flows from the financial asset expire, or when the financial asset and all substantial risks and rewards are transferred. A financial liability is derecognised when it is extinguished, discharged, cancelled or expires. Financial instruments are classified and measured as set out below. Effective interest rate method The effective interest method is a method of calculating the amortised cost of a financial asset or a financial liability (or group of financial assets or financial liabilities) and of allocating the interest income or interest expense over the relevant period. The effective interest rate is the rate that exactly discounts estimated future cash payments or receipts through the expected life of the financial instrument or, when appropriate, a shorter period to the net carrying amount of the financial asset or financial liability. Income is recognised on an effective interest rate basis for debt instruments other than those financial assets ‘at fair value through profit or loss’. 47 Vintage Energy Ltd Annual Report 2020 Classification and subsequent measurement Trade and other receivables Trade and other receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market and are stated at amortised cost using the effective interest rate method, less provision for impairment. Discounting is omitted where the effect of discounting is immaterial. The entity’s cash and cash equivalents, trade and most other receivables fall into this category of financial instruments. Financial liabilities The entity’s financial liabilities include trade and other payables. Non-derivative financial liabilities are subsequently measured at amortised cost using the effective interest rate method. Fair value Fair value is determined based on current bid prices for all quoted investments. Valuation techniques are applied to determine the fair value for all unlisted securities, including recent arm’s length transactions, reference to similar instruments and option pricing models. 4.16 Impairment of financial assets Financial assets are assessed for indicators of impairment at each reporting date. Financial assets are impaired where there is objective evidence that as a result of one or more events that occurred after the initial recognition of the financial asset the estimated future cash flows of the investment have been impacted. For financial assets carried at amortised cost, the amount of the impairment is the difference between the asset’s carrying amount and the present value of estimated future cash flows, discounted at the original effective interest rate. The carrying amount of financial assets including uncollectible trade receivables is reduced by the impairment loss through the use of an allowance account. Subsequent recoveries of amounts previously written off are credited against the allowance account. Changes in the carrying amount of the allowance account are recognised in profit. 4.17 Government grants The Company’s projects at times may be supported by grants received from the federal, state and local governments. Government grants received in relation to drilling of exploration wells are initially deferred as a liability until the grant is spent. Once spent it is then recognised as a reduction in the carrying value of exploration and evaluation asset or Income if the expenditure relating to the grant is expensed. 4.18 Share-based payments All goods and services received in exchange for the grant of any share-based payment are measured at their fair values. Where employees are rewarded using share-based payments, the fair values of employees’ services are determined indirectly by reference to the fair value of the equity instruments granted. This fair value is appraised at the grant date and excludes the impact of non-market vesting conditions (for example profitability and sales growth targets and performance conditions). All share-based remuneration is ultimately recognised as an expense in profit or loss with a corresponding credit to share option reserve. If vesting periods or other vesting conditions apply, the expense is allocated over the vesting period, based on the best available estimate of the number of share options expected to vest. Non-market vesting conditions are included in assumptions about the number of options or rights that are expected to become exercisable. Estimates are subsequently revised if there is any indication that the number of share options or rights expected to vest differs from previous estimates. Any cumulative adjustment prior to vesting is recognised in the current period. No adjustment is made to any expense recognised in prior periods if share options or rights ultimately exercised are different to that estimated on vesting. Upon exercise of share options, the proceeds received net of any directly attributable transaction costs are allocated to share capital. 4.19 Leases Current year At inception of a contract, the Company assesses whether a lease exists - that is, does the contract convey the right to control the use of an identified asset for a period of time in exchange for consideration. This involves an assessment of whether: 48    The contract involves the use of an identified asset - this may be explicitly or implicitly identified within the agreement. If the supplier has a substantive substitution right then there is no identified asset. The Company has the right to obtain substantially all of the economic benefits from the use of the asset throughout the period of use. The Company has the right to direct the use of the asset, that is, decision-making rights in relation to changing how and for what purpose the asset is used. At the lease commencement, the Company recognises a right-of-use asset and associated lease liability for the lease term. The lease term includes extension periods where the Company believes it is reasonably certain that the option will be exercised. The right-of-use asset is measured using the cost model where cost on initial recognition comprises of the lease liability, initial direct costs, prepaid lease payments, estimated cost of removal and restoration less any lease incentives received. The right-of-use asset is depreciated over the lease term on a straight line basis and assessed for impairment in accordance with the impairment of assets accounting policy. The lease liability is initially measured at the present value of the remaining lease payments at the commencement of the lease. The discount rate is the rate implicit in the lease. However, where this cannot be readily determined then the Company’s incremental borrowing rate is used. Subsequent to initial recognition, the lease liability is measured at amortised cost using the effective interest rate method. The lease liability is remeasured whether there is a lease modification, change in estimate of the lease term or index upon which the lease payments are based (for example, CPI) or a change in the Company’s assessment of lease term. Where the lease liability is remeasured, the right-of-use asset is adjusted to reflect the remeasurement or is recorded in profit or loss if the carrying amount of the right-of-use asset has been reduced to zero. Accounting policy applicable to comparative period (30 June 2019) Lease payments for operating leases, where substantially all of the risks and benefits remain with the lessor, are charged as expenses on a straight-line basis over the life of the lease term. Lease incentives under operating leases are recognised as a liability and amortised on a straight-line basis over the life of the lease term. 4.20 Going concern Vintage’s financial statements are prepared on the going concern basis which assumes continuity of normal business activities and the realisation of assets and settlement of liabilities and commitments in the normal course of business. During the year ended 30 June 2020 the company recognised a loss of $2,205,848, had net cash outflows from operating and investing activities of $21,372,773, and had accumulated losses of $6,432,653 as at 30 June 2020. The continuation of the Company as a going concern is dependent upon its ability to generate sufficient net cash inflows from operating and financing activities and manage the level of exploration and other expenditure within available cash resources. The Directors consider that the going concern basis of accounting is appropriate, as the company has the following options: • The ability to issue share capital under the Corporations Act 2001, by a share purchase plan, share placement or rights issue; • The option of farming out all or part of its assets; • The option of selling interests in the Company’s assets; and • The option of relinquishing or disposing of rights and interests in certain assets. In the event that the Company is unsuccessful in implementing one or more of the funding options listed above, such circumstances would indicate that a material uncertainty exists that may cast significant doubt as to whether the Company will continue as a going concern and therefore whether it will realise its assets and discharge its liabilities in the normal course of business and at the amounts stated in the financial report. This financial report does not include any adjustments relating to the recoverability and classification of recorded asset amounts or to the amounts and classification of liabilities that might be necessary should the Company not continue as a going concern. 4.21 Comparative figures When required by Accounting Standards, comparative figures have been adjusted to conform to changes in presentation for the current financial year. 4.22 Critical accounting estimates and judgments The directors evaluate estimates and judgments incorporated into the financial statements based on historical knowledge and best available current information. Estimates assume a reasonable expectation of future events and are based on 49 Vintage Energy Ltd Annual Report 2020 current trends and economic data, obtained both externally and within the Company. Actual results may differ from these estimates. The estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognised in the period in which the estimate is revised if the revision affects only that period or in the period of the revision and future periods if the revision affects both current and future periods. Critical judgements in applying the Company’s accounting policies The following critical judgement, including estimations, that management has made in the process of applying the Company’s accounting policies and that had the most significant effect on the amounts recognised in the financial statements. Capitalised exploration and evaluation The Company has capitalised significant exploration and evaluation expenditure on the basis either that this is expected to be recouped through future successful development or alternatively sale of the areas of interest. If, ultimately, the areas of interest are abandoned or are not successfully commercialised, the carrying value of the capitalised exploration and evaluation expenditure would need to be written down to its recoverable amount. Restoration costs The Company has recognised restoration costs on the basis of current estimates of the liability. This estimate requires judgmental assumptions regarding removal date, future environmental legislation, the extent of reclamation activities required, the engineering methodology for estimating cost, future removal technologies in determining the removal cost, and liability specific discount rates to determine the present value of these cash flows. 4.23 Operating segments The Directors have considered the requirements of AASB 8 – Operating Segments and the internal reports that are reviewed by the chief operating decision maker (the Board) in allocating resources and have concluded at this time there are no separately identifiable segments. 50 5 Loss for the year Loss for the year from continuing operations includes the following expenses: Employees benefit expense Short-term employee benefits – salaries and fees (1,786,711) (1,071,114) 30 June 2020 $ 30 June 2019 $ Post-employment benefits Increase in employee benefit provisions Capitalisation of salaries and fees to exploration expenditure Amortisation of performance rights Other staff costs Other expenses Accounting and audit Conferences Consulting expenses Computer expenses Insurances Marketing Travel and accommodation Legal fees Rent (i) Share registry and exchange costs Subscriptions and technical publications Sundry (168,506) (100,135) 197,605 (362,185) (114,007) (101,755) (87,749) 195,338 (608,204) (69,133) (2,333,939) (1,742,617) (58,196) (3,743) (139,810) (121,648) (118,480) (169,608) (56,522) (133,463) - (74,538) (28,933) (123,725) (42,761) (23,833) (325,008) (95,335) (96,843) (98,851) (92,870) (177,392) (134,680) (44,488) (46,723) (69,538) (1,028,666) (1,248,322) (i) Following adoption of AASB 16, rent has been replaced by amortisation of right to use assets and interest on lease liabilities. 6 Income Taxes The prima facie income tax expense on pre-tax accounting profit from operations reconciles to the income tax expense in the financial statements as follows: Loss from operations Income tax (benefit) calculated at 27.5% (2019: 27.5%) Non-deductible expenses Unused tax losses and tax offsets not recognised as deferred tax assets Tax expense/(benefit) Tax expense/(benefit) comprises Current tax expense Tax losses not brought to account Deferred tax liability not brought to account Tax expense (benefit) 30 June 2020 $ 30 June 2019 $ (2,205,848) (3,422,786) (606,608) (941,266) 107,219 499,389 - 250,422 696.344 - (499,389) 5,248,738 (696,344) 3,350,286 (4,749,349) (2,653,942) - - Total tax losses not brought to account at 30 June 2020 total $9,041,172 at 27.5% tax rate applicable. For the Company’s policy on the accounting treatment of income taxes, refer to Note 4.4. 51 Vintage Energy Ltd Annual Report 2020 7 Cash and cash equivalents Cash and cash equivalents consist the following: Cash on hand Cash at bank (1) 30 June 2020 $ 9 30 June 2019 $ 9 3,443,230 22,296,203 3,443,239 22,296,212 (i) Cash balance at 30 June 2019 included restricted cash of $2,301,481, held by the PEL 155 joint operation which could only be utilised for the expenditure programme on PEL 155. Those funds were used in full during the 2020 drilling program. At 30 June 2020, restricted amounts totalled $137,865, relating to security deposits. 8 Trade and other receivables Joint venture receivables GST receivables Other 9 Property, Plant and Equipment Furniture and fittings / Plant and equipment – at cost Balance at 1 July Additions for the year Balance as at 30 June Right of use asset Balance at 1 July Additions for the year (i) Balance as at 30 June Accumulated depreciation and impairment Balance at July Depreciation Expense (ii) Balance 30 June Net Book Value (i) (ii) Recognised 1 July 2019, refer note 3.1 Includes right of use asset depreciation of $123,812 30 June 2020 $ 261,098 46,298 70,911 30 June 2019 $ - 47,329 78,043 378,307 125,372 30 June 2020 $ 197,919 3,450 201,369 - 206,353 206,353 30 June 2019 $ 73,016 124,903 197,919 - - - 47,535 190,648 238,183 2,701 44,834 47,535 169,539 150,384 52 10 Exploration and Evaluation Assets Balance at 1 July Additions for the year (i) PACE grant brought to account (ii) Balance at 30 June 30 June 2020 $ 12,149,492 19,267,778 (2,475,000) 30 June 2019 $ 2,780,793 9,368,699 - 28,942,270 12,149,492 (i) The increase in exploration and evaluation assets during the year included expenditure on: Operated permit $ Non-operated permit $ PEL155 Joint Venture Galilee Deeps Joint Venture - - 6,979,611 5,805,069 ATP2021 Joint Venture 5,508,445 - Cervantes Joint Venture - 545,452 EP126, Bonaparte Basin Other (PEP171, GSEL672) 234,651 194,550 - - Total additions $ 6,979,611 5,805,069 5,508,445 545,452 234,651 194,550 Total additions 5,937,646 13,330,132 19,267,778 Closing balance $ 6,336,614 13,997,633 5,521,755 545,452 2,327,828 212,988 28,942,270 (ii) The PACE grant had previously been held as a liability in the Statement of Financial Position. Refer to Note 12. 11 Trade and other payables Trade and other payables consist of the following: Current Trade payables Accrued expenses PAYG withholding Total trade and other payables 12 Deferred grant income Share of PACE grant received 30 June 2020 $ 62,233 51,458 49,641 163,332 30 June 2019 $ 145,187 232,505 105,034 482,726 30 June 2020 $ 30 June 2019 $ - 2,475,000 The PEL 155 joint venture received a Plan for Accelerating Exploration (“PACE”) grant from the South Australian government to assist in the drilling of an exploration well in PEL 155. The well was successfully drilled during the year, with all grant monies spent. The joint venture received confirmation from government that the obligations of the grant have been acquitted, with the amount held as a liability now offset against exploration assets recognised in the Statement of Financial Position. 53 Vintage Energy Ltd Annual Report 2020 13 Provisions Current Employee Benefits Non-Current Restoration Provision Movement in Employee Benefits Opening balance Movement for the year Closing balance Movement in Restoration Provision Opening balance (i) Change during the year Closing balance 30 June 2020 $ 198,539 198,539 30 June 2019 $ 98,404 98,404 925,000 925,000 925,000 925,000 98,404 100,135 198,539 10,665 87,739 98,404 925,000 - 925,000 - 925,000 925,000 (i) The non-current restoration provision represents the obligations for future rehabilitation of EP126 which were assumed on acquisition. There has been no change in management’s estimate of the future restoration costs. 14 Other financial liabilities Lease liability (i) Other financial liability (ii) (i) Movement in lease liability: Opening balance Lease liability recognised 1 July 2019 (refer note 3.1) Rent payments made during the year Interest expense on lease liability recognised during the year 30 June 2020 $ 82,380 238,000 320,380 - 206,353 (126,445) 2,472 82,380 30 June 2019 $ - - - - - - - - (ii) An Extraordinary General Meeting was held on 29 June 2020 to approve the participation of the Company’s Directors in the FY20 capital raise. The $238,000 received in contribution from Directors at year end was held as a liability until the resulting shares were issued on 7 July 2020, at which time the proceeds were converted from a liability to equity. 54 15 Issued capital Ordinary Shares Founders’ shares Balance at 30 June Shares issued and fully paid: Ordinary Shares (i) Beginning of the year Shares allotted during the period Conversion of Founders’ shares Conversion of performance rights Issued under share-based payments Share issue costs Total ordinary shares Founders’ shares Beginning of the year Transferred to ordinary shares on conversion Total Founders’ shares 30 June 2020 $ 36,891,576 - 30 June 2019 $ 34,392,805 - 36,891,576 34,392,805 30 June 2020 Number 30 June 2020 $ 30 June 2019 Number 30 June 2019 $ 266,575,739 34,392,805 74,560,007 6,160,209 72,638,889 2,615,000 150,000,000 30,000,000 - 725,000 16,666 - 39,628,232 87,000 2,334 - (205,563) 2,387,500 - - 339,956,294 36,891,576 266,575,739 4,200 436,125 - (2,207,729) 34,392,805 - - - - - - 700 (700) - 4,200 (4,200) - Total contributed equity at 30 June 339,956,294 36,891,576 266,575,739 34,392,805 (i) Ordinary Shares Subject to the Constitution and to the terms of issue of Shares, all Shares attract the following rights:   the right to receive notice of and to attend and vote at all general meetings of the Company; the right to receive dividends; and in a winding up or a reduction of capital, the right to participate equally in the distribution of the assets of the Company (both capital and surplus), subject to any amounts unpaid on the Share and, in the case of a reduction, to the terms of the reduction. The following shares were issued during the period:  51,805,556 ordinary shares via a capital placement at $0.036 per share  20,833,333 ordinary shares via a share purchase plan at $0.036 per share  725,000 ordinary shares on the conversion of performance rights  16,666 ordinary shares as part of share-based payments 55 Vintage Energy Ltd Annual Report 2020 16 Share options and Founders’ Rights Founders’ Rights On conversion of the Founders’ Shares, as described above, 7,925,646 Founders’ Rights were issued. The Founders’ Rights will vest and convert into ordinary fully paid shares in the Company 6 months after the 30-day VWAP share price exceeding $0.30. Each of the Founders’ Rights expire at 5:00 pm (ACST) on the Expiry Date being the third anniversary of the issue date of the Founders’ Rights. Share Options During the year the following options were issued. The options expire 17 September 2021. Date options granted 20 August 2019 Exercise price of shares ($) Number under option Fair value of the option 0.35 1,000,000 20,000 The options have been valued using the Black and Scholes method and the following inputs: Share price Option strike price Number of years Risk free rate Volatility Value per option 0.14 0.35 2 2% 69% 0.02 Shares issued on exercise of remuneration performance rights As detailed in the table below, 725,000 shares were issued on conversion of performance rights following the meeting of performance conditions. Employee Incentive Plan The shareholders of the Company approved an Employee Incentive Plan for employees at the Annual General Meeting held on the 27 November 2018. The purpose of the Employee Incentive Plan is to provide an incentive for eligible participants to participate in the future growth of the Company and to offer Options or performance rights to assist with the reward, retention, motivation and recruitment of eligible participants. Eligible participants are any full or part-time employee of the Company or a subsidiary, relevant contractors and casual employees and prospective parties in these capacities. Non-Executive directors (and their associates) are not eligible to participate in the Employee Incentive Plan. Subject to any necessary Shareholder approval, the Board may offer Options or performance rights to Eligible Participants for nil consideration. The following performance rights have been issued pursuant to the scheme to eligible employees. 56 Performance Right Issued date Number Converted on performance condition met Lapsed Balance Value on issue $ Class A Class A Class B Class B Class C Class C June 2019 725,000 (725,000) August 2019 157,500 November 2018 724,000 June 2019 362,500 November 2018 724,000 June 2019 362,500 - - - - - - - - - - - - 157,500 87,000 22,050 724,000 119,460 362,500 724,000 362,500 43,500 79,640 43,500 In addition to the above, 16,667 shares were issued as part of the plan to Plan participants. The fair value on issue was $2,334. Performance rights issued under the Employee Incentive Plan have been issued under the following general performance conditions: Class A performance rights continued employment with the Company for 12 months from date of commencement. Class B performance rights Company books a minimum 2P reserve of 1.0 MMBOE and the executive is still engaged as an employee three years after commencing employment with the company. Class C performance rights at any stage prior to the end three years after signing the employment agreement the Company’s share price (30-day VWAP) reaching a share price (variable in each issue of rights, in this case $0.40) and still being engaged as an executive at the end of the three years. The Rights have been valued using either the Black and Scholes valuation method or the Barrier option method at the date of issue. Performance rights issued to the Managing Director – details of which have been disclosed in the Remuneration report included in the Directors’ report. 17 Interest in Joint Operations The Company has an interest in the following unincorporated Joint Operations whose principal activities are oil and gas exploration: Galilee Basin ATP-743, ATP-744 and ATP-1015 (i) Otway Basin PEL 155 (ii) Otway Basin PEL 171 (iii) Bonaparte Basin EP 126 Gas Storage Exploration Licence (GSEL 672) ATP 2021(iv) PRL 211 (V) PELA 679(vi) 30 June 2020 % interest 30 50 25 100 100 50 42.5 - 30 June 2019 % interest 15 50 - 100 100 - - - (i) Vintage acquired a further 15% contractual interest in the "Deeps" area of ATP 743, ATP 744, and ATP 1015 in 2020 for a total of 30% contractual interest; having funded:  Stage 1a: first $3.35 million of the costs of the Albany-1 drilling and production testing;  Stage 2: 50% of the costs of 2D seismic, Albany-2 drilling and Albany-1 ST1 drilling to a maximum of $5 million. (ii) Vintage had held in its Statement of Financial Position, a liability for its 50% share of the PACE grant received until the grant was formally acquitted during the year. (iii) Vintage may earn up to a 50% legal and beneficial interest in the License, by: expending the Initial Farm-in Obligation, ($450,000) to earn an Initial Farm in Interest of 25%; and (provided the Initial Farm-in Interest has been earned in full) expending the Subsequent Farm-in Obligation ($1,082,000) to earn the Subsequent Farm-in Interest of 25% (for an aggregate 50% interest). (iv) Vintage project-managed the planning and drilling of the first well in the joint venture program, with transfer of its 50% interest in the permit and formal operatorship now having received Ministerial approval. 57 Vintage Energy Ltd Annual Report 2020 (v) Vintage is paying 50% of the estimated cost of the well – approximately $2.0 million contribution by Vintage for 42.5% equity. (vi) Vintage was successful in bidding for Block CO2019-E (PELA 679) (“Block E”) in the south west of the Cooper Basin in South Australia. Once an appropriate land access agreement is in place with the Dieri Aboriginal Corporation RNTBC and the State Government, Vintage will have a 100% interest in the permit with options to finance the firm work program through the potential introduction of a joint venture partner/s. 18 Earnings per share Both the basic and diluted earnings per share have been calculated using the profit attributable to shareholders of the Company as the numerator. The reconciliation of the weighted average number of shares for the purposes of diluted earnings per share to the weighted average number of ordinary shares used in the calculation of basic earnings per share is as follows: 30 June 2020 Number 30 June 2019 Number 278,878,748 217,378,056 278,878,748 217,378,056 Weighted average number of shares used in basic earnings per share Weighted average number of shares used in dilutive earnings per share Potential ordinary shares are antidilutive when their conversion to ordinary shares would increase earnings per share or loss per share. As such, there are no dilutive securities on issue. 19 Commitments In order to maintain rights to tenure of exploration permits, the Company is required to perform minimum work programs specified by various state and national governments. These obligations are subject to renegotiation in certain circumstances such as when application for an extension permit is made and at other times. The minimum work program commitments may be reduced by the Company by entering into sale or farm-out agreements or by relinquishing permit interests. Should the minimum work program not be completed in full or in part in respect of a permit then the Company’s interest in that exploration permit could be either reduced or forfeited. In some instances, a financial penalty may result if the minimum work program is not completed. Approved expenditure for permits may be in excess of the minimum expenditure or work commitment. Where the Company has a financial obligation in relation to approved joint operation exploration expenditure that is greater than the minimum permit work program commitments then these amounts are also reported as a commitment. The current estimated expenditure for approved commitments and minimum work program commitments are as follows: Exploration and evaluation No longer than 1 year Longer than 1 year but less than 5 years Operating leases No longer than 1 year Longer than 1 year and not longer than 5 years Longer than 5 years 30 June 2020 $ 30 June 2019 $ 8,119,000 12,888,000 7,501,000 4,224,000 15,620,000 17,112,000 30 June 2020 $ 30 June 2019 $ - - - - 124,500 124,500 - 249,000 Following the introduction of AASB 16, operating lease commitments are now recognised as liabilities. 58 20 Financial Instruments (a) Capital risk management The Company manages its capital to ensure that it will be able to continue as a going concern and as at 30 June 2020 has no debt. The capital structure of the Company consists of cash and cash equivalents and equity attributable to equity holders of the parent comprising issued capital, reserves and accumulated losses. Financial risk management objectives (b) The Company’s management provides services to the business, and manages the financial risks relating to the operations of the Company. The Company does not trade or enter into financial instruments, including derivative financial instruments, for speculative purposes. The use of financial derivatives is governed by the Company’s policies approved by the Board of directors. (c) Categories of financial instruments Financial assets Cash and cash equivalents Trade and other receivables Total Financial assets Financial liabilities Trade and other payables Lease liability Other financial liability 30 June 2020 $ 30 June 2019 $ 3,443,239 22,296,212 378,307 125,372 3,821,546 22,421,584 163,332 82,380 238,000 483,712 482,726 - - 482,726 Commodity price risk management (d) The Company does not currently have any projects in production and has no exposure to commodity price fluctuations. Liquidity risk management (e) The Company manages liquidity risk by maintaining adequate reserves, banking facilities and reserve borrowing facilities by continuously monitoring forecast and actual cash flows and matching the maturity profiles of financial assets and liabilities. Liquidity and interest risk tables The following tables detail the Company’s remaining contractual maturity for its non-derivative financial assets and liabilities. The tables have been prepared based on the undiscounted cash flows expected to be received/paid by the Company. Weighted average effective interest rate Less than 1month 1 to 3 months 3 months to 1 year 1 to 5 years 5 plus Total 2020 Financial assets: Non-interest bearing 0.00% 9 378,307 Variable interest rate 0.75% 3,305,365 Fixed interest rate 1.50% Financial liabilities: Non-interest bearing - - - - 137,865 - - (401,332) (82,380) 3,305,374 (23,025) 55,485 - - - - - - - - - - 378,316 3,305,365 137,865 (483,712) 3,337,834 59 Vintage Energy Ltd Annual Report 2020 Weighted average effective interest rate 0.00% 0.75% 1.50% 2019 Financial assets: Non-interest bearing Variable interest rate Fixed interest rate Financial liabilities: Non-interest bearing Less than 1month 1 to 3 months 3 months to 1 year 1 to 5 years 5 plus Total 11 125,372 4,964,720 2,301,481 7,000,000 8,000,000 30,000 - (482,726) - 11,964,731 9,944,127 30,000 - - - - - - - - - - 125,383 7,266,201 15,030,000 (482,726) 21,938,858 Interest rate risk management (f) The Company is exposed to interest rate risk as it earns interest at floating rates from a portion of its cash and cash equivalents. The Company places a portion of its funds into short term fixed interest deposits which provide short term certainty over the interest rate earned. Interest rate sensitivity analysis (g) If the average interest rate during the year had increased/decreased by 10% the Company’s net loss after tax would increase/decrease by $36,731. Credit risk management (h) The Company does not have any significant credit risk exposure to any single counterparty or any group of counterparties having similar characteristics. The credit risk on liquid funds and financial instruments is limited because the counterparties are banks with high credit-ratings assigned by international credit-rating agencies. The carrying amount of financial assets recorded in the financial statements, net of any allowances for losses, represents the Company’s maximum exposure to credit risk. Fair value of financial instruments (i) The Directors consider that the carrying amount of financial assets and financial liabilities recorded in the financial statements approximates their fair values (2019: net fair value). 21 Contingent Liabilities No contingent liabilities exist as at the date of the financial report. 22 Related Party Transactions (a) Key Management Personnel Key management of the Company are the executive members of Vintage Energy Limited and its Board of Directors. Key management personnel remuneration, as detailed in the Company’s Remuneration Report within the Directors’ Report, includes the following expenses: Short-term employee benefits Share based payments Post-employment benefits (b) Transactions with affiliates 30 June 2020 $ 591,110 178,082 53,583 822,775 30 June 2019 $ 471,320 573,090 42,773 1,087,183 An affiliate of the Managing Director is employed with the Company in a technical position, with remuneration based on an arm’s length basis and at a rate consistent to the position filled. 60 23 Remuneration of Auditors Audit or review of the financial report Other Services Other services include fees for taxation services. The company’s auditor is Grant Thornton Audit Pty Ltd. 24 Cash Flow Information Reconciliation of cash flows from operating activities Loss for the year Depreciation Shares options and performance rights expensed Wages and salaries capitalised Recoveries offset against exploration Changes in assets and liabilities: (Increase)/decrease in trade and other receivables Increase in provisions Increase/(decrease) in trade and other payables 30 June 2020 $ 30 June 2019 $ 48,000 40,000 2,500 2,000 50,500 42,000 30 June 2020 $ 30 June 2019 $ (2,205,848) (3,422,786) 190,648 44,834 382,185 892,204 (197,605) (195,338) (1,279,738) - (5,792) (100,135) (145,693) (35,044) 87,749 166,870 (3,361,978) (2,461,511) 25 Subsequent Events Other than the matters disclosed below, the Directors are not aware of any other matters or circumstances, other than those referred to in this report, that have significantly affected or may significantly affect: - - - the Company’s operations the results of the operations in the future financial years; or the Company’s state of affairs in future financial years. On 9 July 2020, the Company issued 10,694,444 shares to Directors at $0.036 per share, as part of the share capital placement announced on 30 April 2020. The shares were issued after an Extraordinary General Meeting on 29 June 2020 obtained shareholder approval for the participation of Directors in the placement. Funds for the placement had been received prior to 30 June 2020. Mr. Ian Northcott resigned as Alternate Director to Mr. Ian Howarth, subsequent to year end, effective 11 August 2020. 61 Vintage Energy Ltd Annual Report 2020 On 17 September 2020, the Company announced a share placement and rights issue at $0.06 to raise approximately $15,000,000. The funds raised to be used for: - - - - - - Vali Field connection into the Moomba gathering system; Drilling of two further Vali Field wells; Drilling the Odin prospect; Testing the Nangwarry CO2 discovery; Long lead items for drilling the Cervantes prospect; and Geological, geophysical and engineering studies. 26 Company Information The principal place of business of the company is 58 King William Road, Goodwood SA 5034. 62 Directors’ Declaration In the opinion of the Directors of Vintage Energy Limited: 1. The financial statements and notes of Vintage Energy Limited are in accordance with the Corporations Act 2001, including: i. ii. Giving a true and fair view of its financial position as at 30 June 2020 and of its performance for the financial year ended on that date; Complying with Australian Accounting Standards (including Interpretations) and the Corporations Regulations 2001; the Australian Accounting 2. The Managing Director and the Chief Financial Officer have each declared that: i. ii. the financial records of the Company for the year ended have been properly maintained in accordance with section 295A of the Corporations Act 2001; the financial statements and notes for the financial year comply with the Accounting Standards; and iii. the financial statements and notes give a true and fair view; and 3. There are reasonable grounds to believe that Vintage Energy Limited will be able to pay its debts as and when they become due and payable. Signed in accordance with a resolution of the Directors. R G Nelson Chairman Dated the 30th day of September 2020 63 Vintage Energy Ltd Annual Report 2020 Independent Auditor’s Report Independent Auditor’s Report To the Members of Vintage Energy Limited Independent Auditor’s Report Report on the audit of the financial report To the Members of Vintage Energy Limited Independent Auditor’s Report Report on the audit of the financial report Opinion To the Members of Vintage Energy Limited Level 3, 170 Frome Street Adelaide SA 5000 Correspondence to: GPO Box 1270 Level 3, 170 Frome Street Adelaide SA 5001 Adelaide SA 5000 T +61 8 8372 6666 Correspondence to: Level 3, 170 Frome Street GPO Box 1270 Adelaide SA 5000 Adelaide SA 5001 Correspondence to: T +61 8 8372 6666 GPO Box 1270 Adelaide SA 5001 T +61 8 8372 6666 Report on the audit of the financial report We have audited the financial report of Vintage Energy Limited (the Company) which comprises the statement of financial position as at 30 June 2020, the statement of profit or loss and other comprehensive income, statement of changes in Opinion equity and statement of cash flows for the year then ended, and notes to the financial statements, including a summary of significant accounting policies, and the Directors’ declaration. We have audited the financial report of Vintage Energy Limited (the Company) which comprises the statement of financial Opinion position as at 30 June 2020, the statement of profit or loss and other comprehensive income, statement of changes in In our opinion, the accompanying financial report of the Company is in accordance with the Corporations Act 2001, equity and statement of cash flows for the year then ended, and notes to the financial statements, including a summary of including: We have audited the financial report of Vintage Energy Limited (the Company) which comprises the statement of financial significant accounting policies, and the Directors’ declaration. position as at 30 June 2020, the statement of profit or loss and other comprehensive income, statement of changes in a giving a true and fair view of the Company’s financial position as at 30 June 2020 and of its performance for the year equity and statement of cash flows for the year then ended, and notes to the financial statements, including a summary of In our opinion, the accompanying financial report of the Company is in accordance with the Corporations Act 2001, significant accounting policies, and the Directors’ declaration. including: b complying with Australian Accounting Standards and the Corporations Regulations 2001. In our opinion, the accompanying financial report of the Company is in accordance with the Corporations Act 2001, a giving a true and fair view of the Company’s financial position as at 30 June 2020 and of its performance for the year including: ended on that date; and ended on that date; and a giving a true and fair view of the Company’s financial position as at 30 June 2020 and of its performance for the year b complying with Australian Accounting Standards and the Corporations Regulations 2001. Basis for opinion ended on that date; and b complying with Australian Accounting Standards and the Corporations Regulations 2001. 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 Basis for opinion 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 We conducted our audit in accordance with Australian Auditing Standards. Our responsibilities under those standards are Professional Accountants (the Code) that are relevant to our audit of the financial report in Australia. We have also fulfilled Basis for opinion further described in the Auditor’s Responsibilities for the Audit of the Financial Report section of our report. We are our other ethical responsibilities in accordance with the Code. independent of the Group in accordance with the auditor independence requirements of the Corporations Act 2001 and We conducted our audit in accordance with Australian Auditing Standards. Our responsibilities under those standards are the ethical requirements of the Accounting Professional and Ethical Standards Board’s APES 110 Code of Ethics for We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion. further described in the Auditor’s Responsibilities for the Audit of the Financial Report section of our report. We are Professional Accountants (the Code) that are relevant to our audit of the financial report in Australia. We have also fulfilled independent of the Group in accordance with the auditor independence requirements of the Corporations Act 2001 and our other ethical responsibilities in accordance with the Code. the ethical requirements of the Accounting Professional and Ethical Standards Board’s APES 110 Code of Ethics for Professional Accountants (the Code) that are relevant to our audit of the financial report in Australia. We have also fulfilled We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion. our other ethical responsibilities in accordance with the Code. Material uncertainty related to going concern We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion. We draw attention to Note 4.20 in the financial statements, which indicates that the Company incurred a net loss of $2,205,848 during the year ended 30 June 2020, had net cash outflows from operating and investing activities of $21,372,933, and had Material uncertainty related to going concern accumulated losses of $6,432,653 as at 30 June 2020. As stated in Note 4.20, these events or conditions, along with other matters as set forth in Note 4.20, indicate that a material uncertainty exists that may cast doubt on the Company’s ability to We draw attention to Note 4.20 in the financial statements, which indicates that the Company incurred a net loss of $2,205,848 continue as a going concern. Our opinion is not modified in respect of this matter. Material uncertainty related to going concern during the year ended 30 June 2020, had net cash outflows from operating and investing activities of $21,372,933, and had accumulated losses of $6,432,653 as at 30 June 2020. As stated in Note 4.20, these events or conditions, along with other We draw attention to Note 4.20 in the financial statements, which indicates that the Company incurred a net loss of $2,205,848 matters as set forth in Note 4.20, indicate that a material uncertainty exists that may cast doubt on the Company’s ability to during the year ended 30 June 2020, had net cash outflows from operating and investing activities of $21,372,933, and had continue as a going concern. Our opinion is not modified in respect of this matter. accumulated losses of $6,432,653 as at 30 June 2020. As stated in Note 4.20, these events or conditions, along with other matters as set forth in Note 4.20, indicate that a material uncertainty exists that may cast doubt on the Company’s ability to continue as a going concern. Our opinion is not modified in respect of this matter. Grant Thornton Audit Pty Ltd ACN 130 913 594 a subsidiary or related entity of Grant Thornton Australia Ltd ABN 41 127 556 389 www.grantthornton.com.au 64 ‘Grant Thornton’ refers to the brand under which the Grant Thornton member firms provide assurance, tax and advisory services to their clients and/or refers to one or more member firms, as the context requires. Grant Thornton Australia Ltd is a member firm of Grant Thornton International Ltd (GTIL). GTIL and the member firms are not a worldwide partnership. GTIL and each member firm is a separate legal entity. Services are Grant Thornton Audit Pty Ltd ACN 130 913 594 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 a subsidiary or related entity of Grant Thornton Australia Ltd ABN 41 127 556 389 another and are not liable for one another’s acts or omissions. In the Australian context only, the use of the term ‘Grant Thornton’ may refer to Grant Thornton Australia Limited ABN 41 127 556 389 and its Australian subsidiaries and related entities. GTIL is not an Australian related entity to ‘Grant Thornton’ refers to the brand under which the Grant Thornton member firms provide assurance, tax and advisory services to their clients Grant Thornton Australia Limited. Grant Thornton Audit Pty Ltd ACN 130 913 594 and/or refers to one or more member firms, as the context requires. Grant Thornton Australia Ltd is a member firm of Grant Thornton International Ltd (GTIL). GTIL and the member firms are not a worldwide partnership. GTIL and each member firm is a separate legal entity. Services are a subsidiary or related entity of Grant Thornton Australia Ltd ABN 41 127 556 389 Liability limited by a scheme approved under Professional Standards Legislation. 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’ refers to the brand under which the Grant Thornton member firms provide assurance, tax and advisory services to their clients Grant Thornton Australia Limited ABN 41 127 556 389 and its Australian subsidiaries and related entities. GTIL is not an Australian related entity to and/or refers to one or more member firms, as the context requires. Grant Thornton Australia Ltd is a member firm of Grant Thornton International Grant Thornton Australia Limited. 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 Liability limited by a scheme approved under Professional Standards Legislation. another and are not liable for one another’s acts or omissions. In the Australian context only, the use of the term ‘Grant Thornton’ may refer to Grant Thornton Australia Limited ABN 41 127 556 389 and its Australian subsidiaries and related entities. GTIL is not an Australian related entity to Grant Thornton Australia Limited. Liability limited by a scheme approved under Professional Standards Legislation. www.grantthornton.com.au www.grantthornton.com.au Level 3, 170 Frome Street Adelaide SA 5000 Correspondence to: GPO Box 1270 Level 3, 170 Frome Street Adelaide SA 5001 Adelaide SA 5000 T +61 8 8372 6666 Correspondence to: Level 3, 170 Frome Street GPO Box 1270 Adelaide SA 5000 Adelaide SA 5001 Correspondence to: T +61 8 8372 6666 GPO Box 1270 Adelaide SA 5001 T +61 8 8372 6666 Independent Auditor’s Report To the Members of Vintage Energy Limited Independent Auditor’s Report Report on the audit of the financial report To the Members of Vintage Energy Limited Independent Auditor’s Report Opinion Report on the audit of the financial report To the Members of Vintage Energy Limited We have audited the financial report of Vintage Energy Limited (the Company) which comprises the statement of financial Report on the audit of the financial report position as at 30 June 2020, the statement of profit or loss and other comprehensive income, statement of changes in Opinion equity and statement of cash flows for the year then ended, and notes to the financial statements, including a summary of significant accounting policies, and the Directors’ declaration. We have audited the financial report of Vintage Energy Limited (the Company) which comprises the statement of financial Opinion position as at 30 June 2020, the statement of profit or loss and other comprehensive income, statement of changes in In our opinion, the accompanying financial report of the Company is in accordance with the Corporations Act 2001, equity and statement of cash flows for the year then ended, and notes to the financial statements, including a summary of We have audited the financial report of Vintage Energy Limited (the Company) which comprises the statement of financial including: significant accounting policies, and the Directors’ declaration. position as at 30 June 2020, the statement of profit or loss and other comprehensive income, statement of changes in a giving a true and fair view of the Company’s financial position as at 30 June 2020 and of its performance for the year equity and statement of cash flows for the year then ended, and notes to the financial statements, including a summary of In our opinion, the accompanying financial report of the Company is in accordance with the Corporations Act 2001, ended on that date; and significant accounting policies, and the Directors’ declaration. including: b complying with Australian Accounting Standards and the Corporations Regulations 2001. In our opinion, the accompanying financial report of the Company is in accordance with the Corporations Act 2001, a giving a true and fair view of the Company’s financial position as at 30 June 2020 and of its performance for the year a giving a true and fair view of the Company’s financial position as at 30 June 2020 and of its performance for the year b complying with Australian Accounting Standards and the Corporations Regulations 2001. including: ended on that date; and Basis for opinion ended on that date; and b complying with Australian Accounting Standards and the Corporations Regulations 2001. 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 Basis for opinion 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 We conducted our audit in accordance with Australian Auditing Standards. Our responsibilities under those standards are Professional Accountants (the Code) that are relevant to our audit of the financial report in Australia. We have also fulfilled further described in the Auditor’s Responsibilities for the Audit of the Financial Report section of our report. We are Basis for opinion our other ethical responsibilities in accordance with the Code. independent of the Group in accordance with the auditor independence requirements of the Corporations Act 2001 and We conducted our audit in accordance with Australian Auditing Standards. Our responsibilities under those standards are the ethical requirements of the Accounting Professional and Ethical Standards Board’s APES 110 Code of Ethics for We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion. further described in the Auditor’s Responsibilities for the Audit of the Financial Report section of our report. We are Professional Accountants (the Code) that are relevant to our audit of the financial report in Australia. We have also fulfilled independent of the Group in accordance with the auditor independence requirements of the Corporations Act 2001 and our other ethical responsibilities in accordance with the Code. the ethical requirements of the Accounting Professional and Ethical Standards Board’s APES 110 Code of Ethics for Material uncertainty related to going concern Professional Accountants (the Code) that are relevant to our audit of the financial report in Australia. We have also fulfilled We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion. our other ethical responsibilities in accordance with the Code. We draw attention to Note 4.20 in the financial statements, which indicates that the Company incurred a net loss of $2,205,848 during the year ended 30 June 2020, had net cash outflows from operating and investing activities of $21,372,933, and had 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 accumulated losses of $6,432,653 as at 30 June 2020. As stated in Note 4.20, these events or conditions, along with other matters as set forth in Note 4.20, indicate that a material uncertainty exists that may cast doubt on the Company’s ability to We draw attention to Note 4.20 in the financial statements, which indicates that the Company incurred a net loss of $2,205,848 continue as a going concern. Our opinion is not modified in respect of this matter. during the year ended 30 June 2020, had net cash outflows from operating and investing activities of $21,372,933, and had Material uncertainty related to going concern accumulated losses of $6,432,653 as at 30 June 2020. As stated in Note 4.20, these events or conditions, along with other We draw attention to Note 4.20 in the financial statements, which indicates that the Company incurred a net loss of $2,205,848 matters as set forth in Note 4.20, indicate that a material uncertainty exists that may cast doubt on the Company’s ability to during the year ended 30 June 2020, had net cash outflows from operating and investing activities of $21,372,933, and had continue as a going concern. Our opinion is not modified in respect of this matter. accumulated losses of $6,432,653 as at 30 June 2020. As stated in Note 4.20, these events or conditions, along with other matters as set forth in Note 4.20, indicate that a material uncertainty exists that may cast doubt on the Company’s ability to continue as a going concern. Our opinion is not modified in respect of this matter. Grant Thornton Audit Pty Ltd ACN 130 913 594 a subsidiary or related entity of Grant Thornton Australia Ltd ABN 41 127 556 389 www.grantthornton.com.au ‘Grant Thornton’ refers to the brand under which the Grant Thornton member firms provide assurance, tax and advisory services to their clients and/or refers to one or more member firms, as the context requires. Grant Thornton Australia Ltd is a member firm of Grant Thornton International Ltd (GTIL). GTIL and the member firms are not a worldwide partnership. GTIL and each member firm is a separate legal entity. Services are Grant Thornton Audit Pty Ltd ACN 130 913 594 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 a subsidiary or related entity of Grant Thornton Australia Ltd ABN 41 127 556 389 another and are not liable for one another’s acts or omissions. In the Australian context only, the use of the term ‘Grant Thornton’ may refer to Grant Thornton Australia Limited ABN 41 127 556 389 and its Australian subsidiaries and related entities. GTIL is not an Australian related entity to ‘Grant Thornton’ refers to the brand under which the Grant Thornton member firms provide assurance, tax and advisory services to their clients Grant Thornton Audit Pty Ltd ACN 130 913 594 and/or refers to one or more member firms, as the context requires. Grant Thornton Australia Ltd is a member firm of Grant Thornton International Grant Thornton Australia Limited. Ltd (GTIL). GTIL and the member firms are not a worldwide partnership. GTIL and each member firm is a separate legal entity. Services are a subsidiary or related entity of Grant Thornton Australia Ltd ABN 41 127 556 389 Liability limited by a scheme approved under Professional Standards Legislation. 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’ refers to the brand under which the Grant Thornton member firms provide assurance, tax and advisory services to their clients Grant Thornton Australia Limited ABN 41 127 556 389 and its Australian subsidiaries and related entities. GTIL is not an Australian related entity to and/or refers to one or more member firms, as the context requires. Grant Thornton Australia Ltd is a member firm of Grant Thornton International Grant Thornton Australia Limited. 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 Liability limited by a scheme approved under Professional Standards Legislation. Grant Thornton Australia Limited ABN 41 127 556 389 and its Australian subsidiaries and related entities. GTIL is not an Australian related entity to Grant Thornton Australia Limited. Liability limited by a scheme approved under Professional Standards Legislation. www.grantthornton.com.au www.grantthornton.com.au Key audit matters Key audit matters are those matters that, in our professional judgement, were of most significance in our audit of the financial Key audit matters report of the current period. These matters were addressed in the context of our audit of the financial report as a whole, and in Key audit matters are those matters that, in our professional judgement, were of most significance in our audit of the financial forming our opinion thereon, and we do not provide a separate opinion on these matters. report of the current period. These matters were addressed in the context of our audit of the financial report as a whole, and in In addition to the matter described in the Material uncertainty related to going concern section, we have determined the forming our opinion thereon, and we do not provide a separate opinion on these matters. matters described below to be the key audit matters to be communicated in our report. In addition to the matter described in the Material uncertainty related to going concern section, we have determined the Key audit matter matters described below to be the key audit matters to be communicated in our report. How our audit addressed the key audit matter Exploration and evaluation assets - Notes 4.13 & 10 Key audit matter At 30 June 2020 the carrying value of exploration and Exploration and evaluation assets - Notes 4.13 & 10 evaluation assets was $28,942,270. At 30 June 2020 the carrying value of exploration and In accordance with AASB 6 Exploration for and Evaluation of evaluation assets was $28,942,270. Mineral Resources, the Company is required to assess at In accordance with AASB 6 Exploration for and Evaluation of each reporting date if there are any triggers for impairment Mineral Resources, the Company is required to assess at which may suggest the carrying value is in excess of the each reporting date if there are any triggers for impairment recoverable value. which may suggest the carrying value is in excess of the The process undertaken by management to assess whether recoverable value. there are any impairment triggers in each area of interest The process undertaken by management to assess whether involves an element of management judgement. there are any impairment triggers in each area of interest This area is a key audit matter due to the significant involves an element of management judgement. judgement involved in determining the existence of This area is a key audit matter due to the significant impairment triggers. judgement involved in determining the existence of impairment triggers. How our audit addressed the key audit matter Our procedures included, amongst others:  obtaining the management reconciliation of capitalised Our procedures included, amongst others:    conducting a detailed review of management’s  obtaining the management reconciliation of capitalised   conducting a detailed review of management’s exploration and evaluation expenditure and agreeing to the general ledger; exploration and evaluation expenditure and agreeing to the reviewing management’s area of interest considerations general ledger; against AASB 6; reviewing management’s area of interest considerations against AASB 6; assessment of trigger events prepared in accordance with AASB 6 including; assessment of trigger events prepared in accordance with  tracing projects to statutory registers, exploration AASB 6 including; licenses and third party confirmations to determine tracing projects to statutory registers, exploration whether a right of tenure existed; licenses and third party confirmations to determine  enquiry of management regarding their intentions to whether a right of tenure existed; carry out exploration and evaluation activity in the  enquiry of management regarding their intentions to relevant exploration area, including review of carry out exploration and evaluation activity in the management’s budgeted expenditure; relevant exploration area, including review of  understanding whether any data exists to suggest that management’s budgeted expenditure; the carrying value of these exploration and evaluation  understanding whether any data exists to suggest that assets are unlikely to be recovered through the carrying value of these exploration and evaluation development or sale; assets are unlikely to be recovered through development or sale;  evaluating the competence, capabilities and objectivity of management’s experts in the evaluation of potential  evaluating the competence, capabilities and objectivity of impairment triggers; and management’s experts in the evaluation of potential  assessing the appropriateness of the related financial impairment triggers; and statement disclosures.  assessing the appropriateness of the related financial Information other than the financial report and auditor’s report thereon statement disclosures. The Directors are responsible for the other information. The other information comprises the information included in the Information other than the financial report and auditor’s report thereon Company’s annual report for the year ended 30 June 2020, but does not include the financial report and our auditor’s report The Directors are responsible for the other information. The other information comprises the information included in the thereon. Company’s annual report for the year ended 30 June 2020, but does not include the financial report and our auditor’s report Our opinion on the financial report does not cover the other information and we do not express any form of assurance thereon. conclusion thereon. Our opinion on the financial report does not cover the other information and we do not express any form of assurance In connection with our audit of the financial report, our responsibility is to read the other information and, in doing so, consider conclusion thereon. whether the other information is materially inconsistent with the financial report or our knowledge obtained in the audit or In connection with our audit of the financial report, our responsibility is to read the other information and, in doing so, consider otherwise appears to be materially misstated. whether the other information is materially inconsistent with the financial report or our knowledge obtained in the audit or If, based on the work we have performed, we conclude that there is a material misstatement of this other information, we are otherwise appears to be materially misstated. required to report that fact. We have nothing to report in this regard. 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. 65 Vintage Energy Ltd Annual Report 2020 Independent Auditor’s Report (continued) Responsibilities of the Directors’ for the financial report 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 The Directors of the Company are responsible for the preparation of the financial report that gives a true and fair view in determine is necessary to enable the preparation of the financial report that gives a true and fair view and is free from material accordance with Australian Accounting Standards and the Corporations Act 2001 and for such internal control as the Directors misstatement, whether due to fraud or error. 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 Company’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 In preparing the financial report, the Directors are responsible for assessing the Company’s ability to continue as a going the Directors either intend to liquidate the Company or to cease operations, or have no realistic alternative but to do so. concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless the Directors either intend to liquidate the Company or to cease operations, or have no realistic alternative but to do so. Auditor’s responsibilities for the audit of the financial report 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 Our objectives are to obtain reasonable assurance about whether the financial report as a whole is free from material is a high level of assurance, but is not a guarantee that an audit conducted in accordance with the Australian Auditing misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance Standards will always detect a material misstatement when it exists. Misstatements can arise from fraud or error and are is a high level of assurance, but is not a guarantee that an audit conducted in accordance with the Australian Auditing considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions Standards will always detect a material misstatement when it exists. Misstatements can arise from fraud or error and are of users taken on the basis of this financial report. 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: http://www.auasb.gov.au/auditors_responsibilities/ar1_2020.pdf. This description forms part of A further description of our responsibilities for the audit of the financial report is located at the Auditing and Assurance our auditor’s report. Standards Board website at: http://www.auasb.gov.au/auditors_responsibilities/ar1_2020.pdf. This description forms part of our auditor’s report. Report on the remuneration report Report on the remuneration report Opinion on the remuneration report Opinion on the remuneration report We have audited the Remuneration Report included in the Directors’ report for the year ended 30 June 2020. We have audited the Remuneration Report included in the Directors’ report for the year ended 30 June 2020. In our opinion, the Remuneration Report of Vintage Energy Limited, for the year ended 30 June 2020 complies with section 300A of the Corporations Act 2001. In our opinion, the Remuneration Report of Vintage Energy Limited, for the year ended 30 June 2020 complies with section 300A of the Corporations Act 2001. Responsibilities 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, The Directors of the Company are responsible for the preparation and presentation of the Remuneration Report in accordance based on our audit conducted in accordance with Australian Auditing Standards. 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 GRANT THORNTON AUDIT PTY LTD Chartered Accountants J L Humphrey Partner – Audit & Assurance J L Humphrey Partner – Audit & Assurance Adelaide, 30 September 2020 Adelaide, 30 September 2020 66 Information Pursuant to the Listing requirements of the ASX Number of holders of equity securities Ordinary Shares At 28 September 2020, the issued capital comprised of 402,429,472 ordinary shares held by 1,342 holders. Unlisted Options At 28 September 2020, there were:   1,500,000 unlisted options, with a $0.30 exercise price and a 13 September 2021 expiry date, held by 1 holder. Options do not carry the right to vote. 5,000,000 unlisted options, with a $0.35 exercise price and a 13 September 2021 expiry date, held by 5 holders, each with a holding of 1,000,000 options. Each option converts to one share. Options do not carry the right to vote. Unlisted Founders’ Rights At 28 September 2020, there were 7,925,646 unlisted Founders’ Rights, with a $nil exercise price and expiry date of 3 September 2021, held by 6 holders, each with a holding of 1,320,941 performance rights. Each performance right converts to one share six months after the share price exceeds $0.30. Performance rights do not carry the right to vote. Employee Performance Rights At 28 September 2020, there were 4,048,000 performance rights on issue with a $nil exercise price. Each performance right converts into one share on the occurrence of certain conditions. They do not carry the right to vote. Spread details as at 28 September 2020 – Ordinary Shares Holding Ranges 1 - 1,000 1,001 - 5,000 5,001 – 10,000 10,001 – 100,000 100,001 – 9,999,999,999 Totals Holders Total Units % Issued Share Capital 18 61 182 679 402 1,342 1,261 241,788 1,497,396 29,687,181 371,001,846 402,429,472 0.00% 0.06% 0.37% 7.38% 92.19% 100.00% Holders less than a marketable parcel = 162. 67 Vintage Energy Ltd Annual Report 2020 Information Pursuant to the Listing requirements of the ASX Number of holders of equity securities (continued) Substantial Shareholders as at 28 September 2020 Number of shares Acorn Capital Limited 20,410,701 % 5.64 % Top Twenty Shareholders as at 28 September 2020 Position Holder Name Holding % 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 BNP PARIBAS NOMS PTY LTD 38,939,867 CS THIRD NOMINEES PTY LIMITED 16,466,833 UBS NOMINEES PTY LTD HSBC CUSTODY NOMINEES (AUSTRALIA) LIMITED MORGAN STANLEY AUSTRALIA SECURITIES (NOMINEE) PTY LIMITED MR DOMINIC VIRGARA HOWZAT SERVICES PTY LTD MR REGINALD GEORGE NELSON & MRS SUSAN MARGARET NELSON N M GIBBINS 15,486,648 14,296,607 12,588,916 8,933,332 7,411,176 7,161,176 6,483,242 JH NOMINEES AUSTRALIA PTY LTD 6,450,000 SMART HOLDINGS PTY LTD AURELIUS RESOURCES PTY LTD MONLEY PTY LTD CATHARINE MARY GIBBINS JESOTO INVESTMENTS PTY LTD JOHN HINDLE JACKSON ROYAL ENERGY PTY LTD HOWZAT SERVICES PTY LTD CLELAND PROJECTS PTY LTD NETWEALTH INVESTMENTS LIMITED 5,944,572 5,833,519 5,744,572 5,661,177 5,661,177 5,661,177 5,208,488 4,555,556 4,066,790 4,000,000 9.68% 4.09% 3.85% 3.55% 3.13% 2.22% 1.84% 1.78% 1.61% 1.60% 1.48% 1.45% 1.43% 1.41% 1.41% 1.41% 1.29% 1.13% 1.01% 0.99% Total Total Issued Capital 186,554,825 46.36% 402,429,472 100.00% 68 Glossary The following Glossary of Terms and Abbreviations is divided into two parts: 1. Resources and Reserves as defined by the SPE-PRMS; 2. General terms commonly used in the upstream petroleum industry. Terms and Abbreviations for Resources and Reserves as per the SPE-PRMS PRMS Petroleum Resources Management System. Reserves and Resources are defined by the Society of Petroleum Engineers (‘SPE’), American Association of Petroleum Geologists (‘AAPG’), World Petroleum Council (‘WPG’) and the Society of Petroleum Evaluation Engineers (‘SPEE’). The detail of the PRMS is available as a download from the website of the SPE: www.spe.org The petroleum resources classification framework is illustrated below: Prospective Resources Those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered (hypothetical) accumulations by application of future development projects. The categories of decreasing certainty are Low, Best and High Estimates. Low, 1U Best, 2U High, 3U Play Lead Prospect Chance of Discovery Low estimate of Prospective Resources. The abbreviation “1U” is an informal, alternative acronym Best estimate of Prospective Resources. The abbreviation “2U” is an informal, alternative acronym. High estimate of Prospective Resources. The abbreviation “3U” is an informal, alternative acronym. A project associated with a prospective trend of potential prospects, but which requires more data acquisition and/or evaluation in order to define specific leads or prospects. The succession of increasing maturity of concept is play, lead and then prospect. A project associated with a potential accumulation that is currently poorly defined and requires more data acquisition and/or evaluation in order to be classified as a prospect. A lead has a greater maturity of concept than a play but less than a prospect. A project associated with a potential accumulation that is sufficiently well defined to represent a viable drilling target and does not require further data acquisition or evaluation i.e. a prospect is mature for drilling. The chance that the accumulation will result in the discovery of petroleum. The term chance is preferred in lieu of risk for general usage. Commonly applied to a drillable prospect where Prospective Resources are estimated and factors include the product of the separate chances of source rock, migration, reservoir and trap. Chance of Development The chance that a prior discovery of petroleum will be commercially developed. Chance of Commerciality For an undiscovered accumulation the chance of commerciality is the product of the chance of discovery and chance of development Discovery Is one or more accumulations of petroleum for which one or more exploratory wells have established through testing, sampling and/or logging the existence of significant quantities of potentially moveable hydrocarbons. In this context “significant” implies that there is evidence of a sufficient quantity of petroleum to justify estimating the in-place volume demonstrated by the well(s) and for evaluating the potential for economic recovery. Contingent Resources Those quantities of petroleum are estimated, as of a given date, to be potentially recoverable from known accumulations, but the applied project(s) are not yet currently mature enough for commercial development due to one or more contingencies. The categories of decreasing certainty are Low, Best and High estimates. 1C 2C 3C Reserves Low estimate of Contingent Resources. Best estimate of Contingent Resources. High estimate of Contingent Resources. Those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. The categories in decreasing certainty are Proved, Probable and Possible. 1P, Proved Proved reserves (deterministic or probabilistic). 2P, Proved and Probable Proved plus Probable reserves (deterministic or probabilistic). 69 Vintage Energy Ltd Annual Report 2020Glossary (continued) 3P, Proved, Probable and Possible Devonian 3P, Proved, Probable and Range of Uncertainty Possible DST Range of Uncertainty Deterministic EP Fault Probabilistic Deterministic Gas Condensate Probabilistic GJ Graben P90 Probabilistic Estimate Proved plus Probable plus Possible reserves (deterministic or probabilistic). A period of time from 419 to 359 million years ago. Proved plus Probable plus Possible reserves (deterministic or probabilistic). The range of estimated quantities of potentially recoverable petroleum in any one of the three categories, Prospective Resources, Contingent Resources and Reserves. Three Drill stem test. A procedure for isolating and testing the pressure, permeability and flow estimates are designated to describe the range, with decreasing certainty from low to high. capacity of a geological formation during the drilling of a well. Mechanical valves are located The range of estimated quantities of potentially recoverable petroleum in any one of the Because the absolute minimum and absolute maximum outcomes are the extreme cases it in a special cylindrical tool and connected at the base of a drill string and are activated into three categories, Prospective Resources, Contingent Resources and Reserves. Three is considered more practical to use low and high estimates as a reasonable representation the set, and open or closed position by applying weight or rotation of the drill pipe estimates are designated to describe the range, with decreasing certainty from low to high. of the range of uncertainty. There are two methods; deterministic and probabilistic. respectively. Because the absolute minimum and absolute maximum outcomes are the extreme cases it A deterministic estimate is a single discrete scenario within a range of outcomes. Each of is considered more practical to use low and high estimates as a reasonable representation the input parameters is a single value. of the range of uncertainty. There are two methods; deterministic and probabilistic. Exploration Permit for petroleum as in the Northern Territory. A fracture in a rock mass, with the movement of one side past the other. The statistical uncertainty of individual reservoir parameters is used to calculate the A deterministic estimate is a single discrete scenario within a range of outcomes. Each of statistical uncertainty of the in-place and recoverable resource volumes. Often a stochastic the input parameters is a single value. Hydrocarbons which are gaseous at reservoir conditions but which condense to liquids (i.e. Monte Carlo) method is used to calculate probability functions by random sampling of when the temperature and pressure falls below the dewpoint. Refer also to condensate. The statistical uncertainty of individual reservoir parameters is used to calculate the the input distributions. The range of uncertainty is selected from volumes sampled at 90%, statistical uncertainty of the in-place and recoverable resource volumes. Often a stochastic 50% and 10% of the output distribution. (i.e. Monte Carlo) method is used to calculate probability functions by random sampling of From the probabilistic method there is a greater than 90% cumulative probability that Is a fault block, generally greater in length than its width that has been downfaulted relative the input distributions. The range of uncertainty is selected from volumes sampled at 90%, quantities estimated would ultimately be exceeded. to the adjacent blocks. 50% and 10% of the output distribution. Gigajoule. A joule is a measure of heating value. 1 GJ is equal to 1 x 109 joules. Hydraulic fracturing P90 P50 Probabilistic Estimate Probabilistic Estimate P50 P10 Probabilistic Estimate Probabilistic Estimate Hydrocarbon P10 Probabilistic Estimate From the probabilistic method there is a greater than 90% cumulative probability that The high pressure injection of “fraccing fluid”, primarily water, minor thickening agents and This category this is considered to be the most likely outcome. From the probabilistic quantities estimated would ultimately be exceeded. suspended proppants (e.g. sand or aluminium oxide micro-pellets) into a well to create method there is an equal (i.e. 50%) probability that quantities estimated would ultimately be cracks propagated in the subsurface rocks for a small radius around the wellbore. When the greater or smaller. pressure is released the solid proppants prevent the cracks from closing (i.e. hold the This category this is considered to be the most likely outcome. From the probabilistic From the probabilistic method there is a less than 10% cumulative probability that quantities fractures open) and allow petroleum to flow more freely into the wellbore as an aid to the method there is an equal (i.e. 50%) probability that quantities estimated would ultimately be estimated would ultimately be exceeded. production recovery process. greater or smaller. From the probabilistic method there is a less than 10% cumulative probability that quantities estimated would ultimately be exceeded. A naturally occurring organic compound comprising hydrogen and carbon. Hydrocarbons can be as simple as methane (CH4), but many are highly complex molecules and can occur as gases, liquids or solids. Two dimensional; usually referring to a seismic survey with a coarse grid of orthogonal lines. Improved Recovery General Terms and Abbreviations Used in the Petroleum Industry The extraction of additional petroleum, beyond primary recovery, from naturally occurring reservoirs by supplementing the natural forces in the reservoir. It includes waterflooding and gas injection for pressure maintenance, secondary processes, tertiary processes and any other means of supplementing natural reservoir recovery processes. Improved recovery also includes thermal and chemical processes to improve the in-situ mobility of viscous forms of petroleum (also called Enhanced Recovery). 2D General Terms and Abbreviations Used in the Petroleum Industry 3D 2D Joule ASX 3D ATP KB ASX B ATP bbl B Bcf bbl Blooie Line Bcf Boe Blooie Line Three dimensional; usually referring to a seismic survey with a fine grid of orthogonal lines. Two dimensional; usually referring to a seismic survey with a coarse grid of orthogonal lines. Australian Securities Exchange. Is the energy dissipated as heat when an electric current of one ampere passes through a resistance of one ohm for one second. Three dimensional; usually referring to a seismic survey with a fine grid of orthogonal lines. Authority to Prospect which is an exploration licence in Queensland. Australian Securities Exchange. Kelly bushing. A hexagonal spline, the kelly drive slides though the kelly bushing and Billion 109, or 1,000 million. permits a length of drill pipe to be drilled into the wellbore. When the kelly is fully descended, the drillstring is lifted, the kelly disconnected and a new length of drillpipe Authority to Prospect which is an exploration licence in Queensland. One barrel of crude oil contains 42 US gallons (or 34.97 imperial gallons, or, 159 litres). re-connected and the drilling process continues. The kelly bushing fits into the rotary Billion 109, or 1,000 million. turntable fixed into the floor of the drill rig. Depth measurement is relative to the top of KB Billion cubic feet. (usually around one foot above the rig floor) but otherwise may be relative to the top of the One barrel of crude oil contains 42 US gallons (or 34.97 imperial gallons, or, 159 litres). rotary table; RT. Large diameter flow line for air or gas drilling, that diverts the flow of air or gas from the rig into a discharge (flare) pit area. Billion cubic feet. Kilometres. Km Km2 LNG LNG Netback Price Boe Bopd Brent Bopd Logs Brent Carboniferous Condensate Carboniferous Condensate Conventional m M MM Net pay Conventional Cretaceous CSG Cretaceous CSG 70 Metres A square kilometre. Liquefied natural gas. Free on board (“FOB”) export price of LNG at the receiving terminal. The buyer is responsible for shipping and transportation. Barrels of oil equivalent. Natural gas is converted to barrels of oil equivalent generally using Large diameter flow line for air or gas drilling, that diverts the flow of air or gas from the rig a ratio of approximately 6,000 cubic feet of natural gas as an amount equivalent to one into a discharge (flare) pit area. barrel of oil. Barrels of oil equivalent. Natural gas is converted to barrels of oil equivalent generally using A liquid flow rate expressed in barrels of oil per day. a ratio of approximately 6,000 cubic feet of natural gas as an amount equivalent to one barrel of oil. Brent crude oil marker. The price of oil from the giant Brent oil field in the North Sea became a reference marker for other types of crude oil, plus or minus a differential for quality and A liquid flow rate expressed in barrels of oil per day. The measurement versus depth or time, or both, of one or more physical quantities in or other factors. Thus Brent Futures Contracts became tradeable on various financial markets around a well. Logs are measured downhole and transmitted through a wireline for Brent crude oil marker. The price of oil from the giant Brent oil field in the North Sea became both for hedging purposes and as a part of commodities trading in general. recording at the surface. Common measurements include the background gamma radiation, a reference marker for other types of crude oil, plus or minus a differential for quality and acoustic velocity, density, and resistance of rocks and the pressure, temperature and flow A period of time 359 to 299 million years ago. other factors. Thus Brent Futures Contracts became tradeable on various financial markets rates of petroleum fluids. both for hedging purposes and as a part of commodities trading in general. A liquid hydrocarbon phase that is slightly lighter than and with less calorific content than crude oil. More usually occurs in association with natural gas. It is gaseous at reservoir A period of time 359 to 299 million years ago. conditions but will condense from gaseous vapour to a liquid at the lesser temperature and A liquid hydrocarbon phase that is slightly lighter than and with less calorific content than pressure at standard surface conditions. crude oil. More usually occurs in association with natural gas. It is gaseous at reservoir Conventional hydrocarbons or Conventional Oil and Gas refers to petroleum, (crude oil and conditions but will condense from gaseous vapour to a liquid at the lesser temperature and raw natural gas) occurring in discrete accumulations or reservoirs where the source of The thickness of reservoir considered to be gas or oil bearing and capable of contributing to pressure at standard surface conditions. hydrocarbons is distant and the hydrocarbons migrate to a trap. The hydrocarbons are production into the wellbore. Usually there will be several cutoff parameters including a Conventional hydrocarbons or Conventional Oil and Gas refers to petroleum, (crude oil and extracted from the ground by conventional means and methods, i.e. after drilling and using porosity minimum, a shale maximum and a water saturation maximum. raw natural gas) occurring in discrete accumulations or reservoirs where the source of the natural reservoir pressure or pumping and can include stimulation. hydrocarbons is distant and the hydrocarbons migrate to a trap. The hydrocarbons are A period of time from 145 to 66 million years ago. extracted from the ground by conventional means and methods, i.e. after drilling and using the natural reservoir pressure or pumping and can include stimulation. Coal seam gas. A period of time from 145 to 66 million years ago. Millions 106 1,000 Coal seam gas. Glossary (continued) Devonian DST EP Fault Gas Condensate GJ Graben Hydraulic fracturing Hydrocarbon Improved Recovery Joule KB Km Km2 LNG LNG Netback Price Logs m M MM Net pay A period of time from 419 to 359 million years ago. Drill stem test. A procedure for isolating and testing the pressure, permeability and flow capacity of a geological formation during the drilling of a well. Mechanical valves are located in a special cylindrical tool and connected at the base of a drill string and are activated into the set, and open or closed position by applying weight or rotation of the drill pipe respectively. Exploration Permit for petroleum as in the Northern Territory. A fracture in a rock mass, with the movement of one side past the other. Hydrocarbons which are gaseous at reservoir conditions but which condense to liquids when the temperature and pressure falls below the dewpoint. Refer also to condensate. Gigajoule. A joule is a measure of heating value. 1 GJ is equal to 1 x 109 joules. Is a fault block, generally greater in length than its width that has been downfaulted relative to the adjacent blocks. The high pressure injection of “fraccing fluid”, primarily water, minor thickening agents and suspended proppants (e.g. sand or aluminium oxide micro-pellets) into a well to create cracks propagated in the subsurface rocks for a small radius around the wellbore. When the pressure is released the solid proppants prevent the cracks from closing (i.e. hold the fractures open) and allow petroleum to flow more freely into the wellbore as an aid to the production recovery process. A naturally occurring organic compound comprising hydrogen and carbon. Hydrocarbons can be as simple as methane (CH4), but many are highly complex molecules and can occur as gases, liquids or solids. The extraction of additional petroleum, beyond primary recovery, from naturally occurring reservoirs by supplementing the natural forces in the reservoir. It includes waterflooding and gas injection for pressure maintenance, secondary processes, tertiary processes and any other means of supplementing natural reservoir recovery processes. Improved recovery also includes thermal and chemical processes to improve the in-situ mobility of viscous forms of petroleum (also called Enhanced Recovery). Is the energy dissipated as heat when an electric current of one ampere passes through a resistance of one ohm for one second. Kelly bushing. A hexagonal spline, the kelly drive slides though the kelly bushing and permits a length of drill pipe to be drilled into the wellbore. When the kelly is fully descended, the drillstring is lifted, the kelly disconnected and a new length of drillpipe re-connected and the drilling process continues. The kelly bushing fits into the rotary turntable fixed into the floor of the drill rig. Depth measurement is relative to the top of KB (usually around one foot above the rig floor) but otherwise may be relative to the top of the rotary table; RT. Kilometres. A square kilometre. Liquefied natural gas. Free on board (“FOB”) export price of LNG at the receiving terminal. The buyer is responsible for shipping and transportation. The measurement versus depth or time, or both, of one or more physical quantities in or around a well. Logs are measured downhole and transmitted through a wireline for recording at the surface. Common measurements include the background gamma radiation, acoustic velocity, density, and resistance of rocks and the pressure, temperature and flow rates of petroleum fluids. Metres 1,000 Millions 106 The thickness of reservoir considered to be gas or oil bearing and capable of contributing to production into the wellbore. Usually there will be several cutoff parameters including a porosity minimum, a shale maximum and a water saturation maximum. 71 Vintage Energy Ltd Annual Report 2020 Glossary (continued) OGIP, OGIIP Devonian DST OOIP, OOIIP Oil Shale EP P&A Fault Gas Condensate GJ PEL Graben Permian Permit Areas Hydraulic fracturing PJ Pool Porosity Hydrocarbon Reflectors Improved Recovery Reservoir Resources Joule Risk KB RL RT RTSTM Km Km2 LNG scf LNG Netback Price scf/d Seismic Logs m M Shale volume MM Net pay Standard conditions Sub-blocks 72 A period of time from 419 to 359 million years ago. Original gas (initially) in place. The estimated quantity of gas which may originally have occurred in a reservoir. Drill stem test. A procedure for isolating and testing the pressure, permeability and flow Original oil (initially) in place. The estimated quantity of oil which may originally have capacity of a geological formation during the drilling of a well. Mechanical valves are located occurred in a reservoir. in a special cylindrical tool and connected at the base of a drill string and are activated into the set, and open or closed position by applying weight or rotation of the drill pipe respectively. Shale, siltstone and marl deposits highly saturated with kerogen. Whether extracted by mining or in-situ processes, the material must be extensively processed to yield a marketable product (synthetic crude oil). They are totally different from Shale Oil Exploration Permit for petroleum as in the Northern Territory. A fracture in a rock mass, with the movement of one side past the other. Plugged and abandoned. Refers to the process of the final abandonment of petroleum wells usually by spotting cement plugs at key intervals within the well to ensure the protection and isolate of aquifers and depleted reservoirs. Any surface wellheads are removed and the general location restored to a natural state. Hydrocarbons which are gaseous at reservoir conditions but which condense to liquids when the temperature and pressure falls below the dewpoint. Refer also to condensate. Gigajoule. A joule is a measure of heating value. 1 GJ is equal to 1 x 109 joules. Petroleum Exploration Licence as used in South Australia. A period of time 299 to 251 million years ago. Is a fault block, generally greater in length than its width that has been downfaulted relative to the adjacent blocks. The land subject of the Permits in which Vintage Energy has an interest from time to time. Petajoule. A joule is a measure of heating value. 1 PJ is equal to 1 x 1015 joules The high pressure injection of “fraccing fluid”, primarily water, minor thickening agents and suspended proppants (e.g. sand or aluminium oxide micro-pellets) into a well to create cracks propagated in the subsurface rocks for a small radius around the wellbore. When the pressure is released the solid proppants prevent the cracks from closing (i.e. hold the fractures open) and allow petroleum to flow more freely into the wellbore as an aid to the production recovery process. An individual and separate accumulation of petroleum in a reservoir. The pore space in a reservoir which is capable of containing fluids, either water, oil or gas. (i.e. the space between beach sand grains). A naturally occurring organic compound comprising hydrogen and carbon. Hydrocarbons can be as simple as methane (CH4), but many are highly complex molecules and can occur as gases, liquids or solids. As in seismic reflectors. Refer to Seismic. A subsurface rock formation containing an individual and separate natural accumulation of The extraction of additional petroleum, beyond primary recovery, from naturally occurring moveable petroleum that is confined by impermeable rocks/ formations and is characterised reservoirs by supplementing the natural forces in the reservoir. It includes waterflooding and by a single-pressure system. gas injection for pressure maintenance, secondary processes, tertiary processes and any other means of supplementing natural reservoir recovery processes. Improved recovery The term “Resources” as used herein is intended to encompass all quantities of petroleum also includes thermal and chemical processes to improve the in-situ mobility of viscous (recoverable and unrecoverable) naturally occurring on or wthin the Earth’s crust, forms of petroleum (also called Enhanced Recovery). discovered and undiscovered, plus those quantities already produced. Is the energy dissipated as heat when an electric current of one ampere passes through a resistance of one ohm for one second. The probability of loss or failure. As “risk” is generally associated with the negative outcome, the term “chance” is preferred for general usage to describe the probability of a discrete event occurring. Retention licence. Where a Contingent Resource has been discovered and development is not viable in the immediate future, a retention licence may be awarded but usually with much less onerous terms (work program and expenditure). Kelly bushing. A hexagonal spline, the kelly drive slides though the kelly bushing and permits a length of drill pipe to be drilled into the wellbore. When the kelly is fully descended, the drillstring is lifted, the kelly disconnected and a new length of drillpipe re-connected and the drilling process continues. The kelly bushing fits into the rotary turntable fixed into the floor of the drill rig. Depth measurement is relative to the top of KB (usually around one foot above the rig floor) but otherwise may be relative to the top of the rotary table; RT. Rotary Table. Refer to KB, kelly bushing. Kilometres. Refers to a flow of gas recovered at the surface as a consequence of well testing but flows at a rate too small to measure. There is sufficient flow to light a flare but insufficient pressure to register on the gauge or enable the flow rate to be calculated. A square kilometre. Standard cubic feet. Usually referring to gas at standard conditions. Liquefied natural gas. A flow rate in standard cubic feet per day. Free on board (“FOB”) export price of LNG at the receiving terminal. The buyer is responsible for shipping and transportation. A seismic survey measures at geophone locations the time for a shock wave propagated at the surface to travel deep into the earth, strike rock strata and reflect back to the surface. The measurement versus depth or time, or both, of one or more physical quantities in or Dynamite as the source has largely been replaced with vibroseis onshore (i.e. Truck around a well. Logs are measured downhole and transmitted through a wireline for mounted thumper plates in tandem) or airgun offshore. A good reflector is the interface recording at the surface. Common measurements include the background gamma radiation, between two rock strata of differing density e.g. sandstone and shale or limestone and acoustic velocity, density, and resistance of rocks and the pressure, temperature and flow mudstone. Interbedded strata thinner than ~10 metres are more difficult to resolve. A survey rates of petroleum fluids. progresses along lines aligned in a grid and with orthogonal cross lines. After suitable computer processing to “stack” the traces of individual geophones into sections these provide a “picture” of the structure of the subsurface reflectors. Metres 1,000 Millions 106 This is the portion of rock which is occupied by “shales” (in fact, usually more correctly called mudstone). For example, a “shaly” sandstone interval may contain 15% shale either as thin laminations or clay minerals within the sandstone matrix. At a certain maxima, the The thickness of reservoir considered to be gas or oil bearing and capable of contributing to shale volume may preclude the occurrence of any effective porosity. production into the wellbore. Usually there will be several cutoff parameters including a porosity minimum, a shale maximum and a water saturation maximum. Measurements of volumes at standard conditions means 14.7 psia and 60°F (US). Petroleum tenements are often defined as blocks. In Queensland there are 25 (5 x 5) sub-blocks within a block. Glossary (continued) TCF TD Tectonic Tenement TJ TOC Trillion cubic feet of gas. Total depth of the well. Pertaining to forces and the geological architecture that results, such as faults, folds etc. Ground granted for exploration or production purposes. Terrajoule; a joule is a measure of heating value. 1 TJ is equal to 1 x 1012 joules Total organic carbon, a measure of the dry weight percent of organic carbon within rocks. Unconventional oil and gas Oil and gas produced by non-traditional sources, means or methods. This covers oil and gas produced from shale formations and coal seams. The formation contains both the hydrocarbon source and reservoir. VR Water saturation WTI Vitrinite reflectance. It is a measure of light reflectance from organic matter in sediments. It provides an indication of the organic maturity of source rocks and whether petroleum may have been generated under heat and pressure and expulsed for potential capture and preservation in reservoir traps. Is the percentage of water occupying the pore space. For an aquifer the water saturation is 100%. For an oil or gas field a portion of the water is displaced and for example, SW of 25% indicates 75% gas or oil within the porosity. Usually reservoirs are water wet and therefore there must be a layer of water coating the surface of the grains of the pore space. This is the connate or irreducible water saturation. The price of West Texas Intermediate crude oil as at the delivery point at Cushing, Oklahoma. It is used as a benchmark for oil pricing but has declined in importance in recent years. Refer to Brent. 73 Vintage Energy Ltd Annual Report 2020 74 75 Vintage Energy Ltd Annual Report 202076 

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