China Online Education Group Annual Report 2023

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Annual Report Acknowledgement of Country Cooper Energy recognises and acknowledges the First Peoples of this nation as the Traditional Owners of the lands where we operate. We pay respects to their Elders past, present and emerging. COOPER ENERGY LIMITED ABN 93 096 170 295 The terms “the Company” and “Cooper Energy” are used in this Annual Report to refer to Cooper Energy Limited and/or its subsidiaries. The terms “2023”, “FY23” and the “2023 financial year” refer to the 12 months ended 30 June 2023 unless otherwise stated. References to 2022, FY22 or 2024, FY24 refer to the 12 months ending 30 June of that year. References to $ are Australian dollars unless specified otherwise. This Annual Report uses terms and abbreviations relevant to the company, its accounts and the petroleum industry. Information on abbreviations and terms, rounding and reserves and resources reporting is provided at the back of this report. 2 COOPER ENERGY ANNUAL REPORT 2023 Our Purpose We find, develop and commercialise Australian gas and oil for domestic markets. We work to deliver a stable and secure supply of domestic gas into markets along the east coast at the low end of the cost curve. We operate with an emphasis on health and safety, environment and sustainability, reliability and shareholder value. Table of Contents Acknowledgement of Country ................................ 2 Reserves & Contingent Resources ..................... 19 Our Purpose .......................................................... 3 Reserves ......................................................... 19 Chairman’s Foreword ............................................ 4 Contingent Resources ..................................... 20 Managing Director’s Report ................................... 6 Review of Operations .......................................... 22 Our Values ........................................................... 11 Safety .............................................................. 22 Our Business ....................................................... 12 Production ....................................................... 22 Our Social and Environmental Commitment ....... 13 Gippsland Basin .............................................. 22 Our Operations .................................................... 14 Otway Basin (Offshore) ................................... 24 Key Results .......................................................... 16 Otway Basin (Onshore) ................................... 25 Financial .......................................................... 16 Cooper Basin ................................................... 27 Operations & Reserves ................................... 17 Portfolio ............................................................... 28 Equity ............................................................... 17 Directors .............................................................. 30 Gas & Oil Revenue .......................................... 18 Executive Leadership .......................................... 34 Capital Expenditure ......................................... 18 Key Performance Indicators ................................. 39 COOPER ENERGY ANNUAL REPORT 2023 3 Chairman’s Foreword This year Cooper Energy welcomed Jane Norman as our Managing Director and CEO in March 2023. Jane brings a wealth of gas and oil experience following an international career spanning more than 20 years and is already driving a renewed focus on operational excellence in the business. 2023 saw the retirement of David Maxwell, who joined Cooper Energy in 2011 at a time when the Company was a small oil-focused explorer. David provided the leadership and strategic direction to target the Southeast Australian gas market, assembling the group of assets we have today, and I acknowledge his contribution to the Company. In FY23, our Company achieved a commendable health and safety performance, with only one recordable injury, a minor finger laceration. Our total recordable injury frequency rate (TRIFR) of 4.38 per million hours worked reflects our commitment to maintaining a safe work environment for our employees. While we regret that the TRIFR rate was not zero, it was ahead of the industry benchmark of 5.68, underscoring our dedication to surpassing industry safety standards. During FY23, the Company achieved a significant milestone, solidifying its position in the Southeast Australian gas market through the successful acquisition of the Orbost Gas Processing Plant. The necessary processes to transfer operatorship of the plant were completed in the course of FY23, with operatorship transferred in the second half of May 2023. There have been significant operational challenges in recent years, including during the transfer of operatorship to us, and I acknowledge the frustration caused for shareholders. Nevertheless, plant ownership will have a significant positive impact on the Company’s future cashflows. I welcome the new Cooper Energy employees who have joined as a result of the plant acquisition and thank everyone for their efforts as we strive for improved plant performance and reliability. There is more work to be done, and the Orbost performance improvement plan is a key operational priority for the Company in FY24. The Company achieved a significant milestone, solidifying its position in the Southeast Australian gas market through the successful acquisition of the Orbost Gas Processing Plant. Under Jane’s leadership, changes have been made to the executive leadership team, to ensure roles have clear accountabilities for performance and that the team is right sized for our operations now and into the future. Chad Wilson will be our new Chief Operating Officer and Nathan Childs will move to the newly created role of Chief Corporate Services Officer. Both executives have extremely strong operational experience and are excellent appointments reflecting the Company’s focus on operational excellence. FY24 Outlook The Company enters FY24 with clear and well- defined objectives. We must complete the BMG abandonment programme on time and on budget, and we must achieve meaningful performance improvements at Orbost. The impact of the latter to the Company’s incremental cashflow and future prospects cannot be understated. Successful outcomes on these two key projects reposition 4 COOPER ENERGY ANNUAL REPORT 2023Board visit to Orbost Gas Processing Plant, August 2023 FY23 scorecard. We have made significant organisational changes in order to achieve the success that we all expect in FY24. I thank all Cooper Energy staff for their hard work, attention to detail and persistence. The company’s long-term strategy is appropriate, and we look forward to achieving improved outcomes for shareholders in FY24 and beyond. John Conde AO Chairman the company for faster growth including the Otway Phase 3 Development (OP3D) project. We have the team, structure and resources to succeed, and the Board is confident that under Jane’s leadership we will see improved outcomes for shareholders. Concluding remarks Despite the operational challenges at Orbost during the transition of operatorship, we are achieving record performance across the key metrics of production, underlying EBITDAX and cashflow. This is especially encouraging as operations at the Athena Gas Plant were also interrupted by unplanned downtime throughout the year. We expect results will improve in FY24 as we bed down both gas hubs, now supported by a fully functioning engineering and technical support team. On behalf of the Board, I express my genuine appreciation to shareholders for their continued patience. I acknowledge that FY23 was below expectations which was reflected in the Company's 5 COOPER ENERGY ANNUAL REPORT 2023Managing Director’s Report This is my first Annual Report since joining Cooper Energy as Managing Director and Chief Executive Officer on 20 March 2023. I would like to thank my predecessor, David Maxwell for leading the business during more than 11 years of service to Cooper Energy. I recognise that this has been a challenging year for the company, with production and financial performance below target as reflected in the FY23 company scorecard performance. This is a disappointing result, and I intend to drive business focus on clear accountability across the leadership team, to foster a performance-focused culture. However, I am pleased to see some early wins in my tenure so far, including the safe and successful transfer of operatorship of the Orbost Gas Processing Plant (OGPP) to Cooper Energy on 22 May. An Operations Taskforce has been established, focused on operational excellence, single point of accountability and ensuring that our Operations team have the right technical and commercial support to maximise performance at both Athena Gas Plant (AGP) and OGPP. Through 2023, we have significantly de-risked the execution of the BMG decommissioning project. I am confident that the expert team we have in Perth, including an experienced team of contractors, will deliver the project safely, with the desired outcomes The release of the Mandatory Code of Conduct on 10 July confirmed that Cooper Energy is exempt from the $12/GJ price cap as a small, domestic market focused producer. Additionally, foundational projects to support new gas developments will be exempt from the Code’s expression of interest and offer timing provisions, which will ensure investment in new gas supply is not inadvertently discouraged. Together with joint venture misalignment, the Federal Government gas market intervention in late 2022 resulted in the delayed sanction of our Otway growth project. I am optimistic that the reasonable action by the Government in this case has opened the door to ongoing communication about the urgent need for more gas supply to come to market, such as further development both onshore and offshore in Victoria, to ensure supply to Australia’s largest domestic gas market. At Cooper Energy we believe gas is not just a transition fuel, but a future fuel and that gas will increasingly be required to support the world’s integration of renewable power. 2023 IN REVIEW Health, safety and the environment I am proud to report that Cooper Energy delivered its FY23 work with a strong health and safety record, and exceptional environmental performance with only minor recordable incidents. We have ended the year with no Lost-Time Injuries and a Total Recordable Injury Frequency Rate of 4.38 ahead of the industry benchmark of 5.68. We will continue to strive for improvement to ensure that all our people go home safely from work. Gas market and strategy Australia requires new gas supply to keep up with the demands of local manufacturing, industrial facilities, heating for homes and businesses, and to provide flexible, firming power for the electricity network and support the integration of variable renewables. Cooper Energy is well positioned to capture more market share, with our existing infrastructure position in both the Otway and Gippsland Basins 6 COOPER ENERGY ANNUAL REPORT 2023Sanction of the project was unfortunately delayed this year, amidst the lack of joint venture alignment and uncertainty of government policy. However, our confidence in the ongoing need for new gas supply continues to grow. There is no better opportunity than to develop resources in the Otway, with a clear path to commercialisation via existing gas processing infrastructure that is close to market. To enable future OP3D drilling, Cooper Energy has worked with other operators in the region to collectively secure the services of a drilling rig. The drilling schedule is expected to commence in Q3 FY25. Cooper Energy has one firm well expected to be drilled in FY26 and options to drill exploration and/ or development wells commencing circa late FY26 or FY27. We will continue to progress joint venture alignment, along with our other FY24 business priorities, to position the project for FID. Financial performance FY23 production met revised guidance, although this was lower than the original figure advised at the start of the year due to ongoing operational issues at OGPP and various unplanned maintenance outages at AGP. These factors, combined with softer spot gas prices caused by a mild start to winter, resulted in full year underlying EBITDAX around the midpoint of the revised guidance, but also below original guidance. In FY24, we will focus on reducing operational costs sustainably, including net G&A and the significant costs associated with the plant variability, including the weekly absorber cleans at OGPP. BMG decommissioning The largest component of our capital budget for FY24 is the delivery of the BMG decommissioning project. Through the last 12 months, we have completed a BMG pre-abandonment programme and locked in the costs wherever possible. Pre-abandonment activities commenced in June and were successfully completed in July. This helps ensure a fast start when the Helix Q7000 heavy well intervention vessel arrives on location at BMG and also reduces the time the Q7000 is on location, thereby reducing the overall project cost. and our portfolio of untapped Reserves and Resources which can be developed back through our existing infrastructure. In November 2022, we announced our gas sales agreement with AGL for the next phase of Otway growth. We appreciate AGL as a high-quality customer with the portfolio size and balance sheet strength to underpin sanction of a new gas development. Despite the project delays, AGL remains committed to this opportunity. Orbost Gas Processing Plant and Gippsland growth opportunities Our priority over the last year, as we prepared for the operatorship of OGPP, has been to ensure that we have the right skills and capabilities to maximise our production output. This has included an expert engineering team based in Melbourne supporting both OGPP and AGP, and a new Plant Superintendent joining us at OGPP who brings experience in running major hazard facilities. Since taking over operatorship of OGPP, our dedicated internal engineering team has been focused on production improvement workstreams to reduce sulphur fouling in the absorber beds and reduce the time taken for cleaning the absorber beds. These include capturing immediate opportunities such as reducing the offline time during weekly absorber cleans. In May 2023, we updated the prospective resource assessment of our exploration portfolio within the Gippsland Basin. Although our immediate focus is to maximise production of Sole through OGPP, we see real opportunity to not only backfill the plant, but also to debottleneck and expand capacity, to meet the growing supply-demand gap in the market. Athena Gas Plant and Otway growth opportunities Our Otway assets have benefited from our increased engineering support capability, with resolution of a long-standing and systemic issue on one of the main sales gas compressors in May. We continue to optimise production from the Casino, Henry and Netherby wells to lengthen the life of the asset. The Otway remains our focus for near-term growth. Front end engineering and design work is complete for the Otway Phase 3 Development (OP3D) project, based on a three well development plan backfilling the existing Casino, Henry and Netherby fields. 7 COOPER ENERGY ANNUAL REPORT 2023Sustainability We are maintaining our Climate Active organisational carbon neutral certification¹ by offsetting our Scope-1, Scope-2 and relevant Scope-3 emissions². This excludes downstream transportation and combustion of products by customers but allows us to offset emissions under our direct control in addition to an increased focus on reducing emissions from our operated sites. We continue to use nature-based carbon offsets including from our partnership with Canopy Nature Based Solutions, a subsidiary of Greening Australia, as well as carbon offsets from other certified Australian and international projects. In November 2022, we announced our contribution of $250,000 towards the $1.1 million private-public- NGO partnership to lay the foundations for high- integrity nature-based carbon projects in Vietnam. The partnership has the potential to deliver a large number of high-integrity carbon credits to Cooper Energy’s portfolio, while delivering biodiversity, social and climate benefits. With both AGP and OGPP now within our control, our focus will turn towards identifying more physical emissions reductions opportunities in our own operations, especially value-accretive opportunities to improve energy efficiency and reduce fuel gas consumption. 2024 Outlook In FY24, our immediate priorities are clear. We must: • Maintain our strong health, safety and environmental performance record; • Maximise OGPP performance, with a clear, deliverable plan to reach nameplate capacity as soon as possible; • Execute BMG abandonment safely, within the minimum time possible and the mid-case cost estimate; • Right-size the business and deliver the cost-out program announced in June; • Maintain our Climate Active organisational carbon neutral certification¹, in conjunction with an increased focus on reducing carbon emissions from our operations to reduce both our emissions footprint and the cost associated with offsets; and • Move forward with our attractive Otway Growth opportunities which leverage existing infrastructure. Orbost Gas Processing Plant Concluding remarks At Cooper Energy we believe gas is not just a transition fuel, but a future fuel, and that gas will increasingly be required to support the world’s integration of renewable power. Australian manufacturers, businesses and homes continue to need access to reliable, low emissions, affordable gas. We are very well positioned to supply this into Southeast Australia. As we move forward as a Company that is now the operator of two strategically located gas plants, we aim to deliver long-term, sustainable value to all shareholders and stakeholders, customers and the communities in which we work. I want to thank our investors, the Board, the Cooper Energy Management Team, our staff and contractors, lenders, customers and suppliers for supporting my transition into this role, and your commitment to the success of Cooper Energy. I look forward to an important financial year 2024, in which we will deliver one of Australia’s largest decommissioning projects and continue to make much-needed gas available to Australian customers. Jane Norman Managing Director and CEO ¹Cooper Energy has been certified by Climate Active as a carbon neutral organisation for its Scope-1, Scope-2 and relevant Scope-3 emissions (embedded energy and business travel). See the 2023 Sustainability Report for further information. ²Organisational carbon emissions voluntarily offset according to Climate Active’s scheme for FY22. These consist of Scope-1 (direct), Scope-2 (purchased electricity) and relevant Scope-3 emissions (embedded energy and business travel). Downstream Customer Scope-3 transportation and combustion emissions are not included. More information regarding Scope definition is available in the Cooper Energy 2023 Sustainability Report. 8 COOPER ENERGY ANNUAL REPORT 2023Orbost Gas Processing Plant 9 COOPER ENERGY ANNUAL REPORT 2023Awareness Care Commitment Collaboration Fairness & Respect Integrity Transparency 10 COOPER ENERGY ANNUAL REPORT 2023Our Values Cooper Energy is a values-driven business with actions guided at all times by our seven core values. Fairness & Respect Valuing diversity and difference, acting without prejudice and communicating with courtesy. Integrity Striving to be consistent, staying true to our values and accountable for our actions. Transparency Being honest, addressing problems and being clear with our communications. Awareness Taking account of all identified key issues in our decisions and considering future impacts. Care Prioritising safety, health, the environment and community. Commitment Staying focused on the core objectives, making pragmatic, and commercial decisions and being decisive with the courage of our convictions. Collaboration Sharing ideas and knowledge, encouraging cooperation, listening to our stakeholders and building long-term relationships. 11 COOPER ENERGY ANNUAL REPORT 2023Our Business Cooper Energy is an Australian company providing energy exclusively for the local domestic market. Our headquarters are in Adelaide, with offices in Perth and Melbourne. We operate two gas processing facilities in regional Victoria which produce gas from offshore fields in the Otway and Gippsland Basins. We have various non-operated interests in the South Australian Cooper Basin and in the onshore Otway Basin in regional South Australia and Victoria. Key Statistics Orbost Gas Processing Plant FY23 Production 2.0 10.7 2P Proved & Probable Reserves¹ at 30 June 2023 2C Contingent Resources¹ at 30 June 2023 5 22 2 65 47.1 59.7 TJe/day 195 222 PJe (36.3 MMboe) 229 296 PJe (48.4 MMboe) Conversion factors: 1bbl of oil = 1 boe, 1 bbl of condensate = 1 boe, 1 TJ = 0.163 kboe | 1 kboe = 6.12 TJe ¹As announced to the ASX 25 August 2023. Other key statistics at 30 June 2023 Market cap Net debt Issued shares Shareholders Employees and contractors 12 Gippsland Basin gas & gas liquids Otway Basin gas & gas liquids Cooper Basin oil $394.7 million $80.9 million 2,631.5 million 9,039 128.9 FTE COOPER ENERGY ANNUAL REPORT 2023Our Social and Environmental Commitment Gender Diversity 57% female representation on the Board of Directors 27% total female workforce Health, Safety & Environment Zero lost time injuries Carbon Neutral 100% Scope-1, Scope-2 and relevant Scope-3 emissions offset¹ Maintaining Climate Active Carbon Neutral Organisation certification² Offshore Gippsland Basin ¹Organisational carbon emissions voluntarily offset according to Climate Active’s scheme for FY22. These consist of Scope-1 (direct), Scope-2 (purchased electricity) and relevant Scope-3 emissions (embedded energy and business travel). Downstream Customer Scope-3 transportation and combustion emissions are not included. More information regarding Scope definition is available in the Cooper Energy 2023 Sustainability Report. ²Cooper Energy has been certified by Climate Active as a carbon neutral organisation for its Scope-1, Scope-2 and relevant Scope-3 emissions (embedded energy and business travel). See the 2023 Sustainability Report for further information. 13 COOPER ENERGY ANNUAL REPORT 2023Our Operations EXPLORATION, DEVELOPMENT & PRODUCTION In the Otway and Gippsland Basins we explore for, develop, and produce natural gas exclusively for the Southeast Australian gas market. In the Cooper Basin onshore in South Australia, we are a joint venture partner in low-cost oil production. Offices Cooper Basin Otway Basin Gippsland Basin Perth • Offshore project support Adelaide • Corporate head office. Cooper Basin • Western Flank oil production, development and exploration. • 25% Cooper Energy interest in PEL 92. Onshore Otway Basin • Gas exploration and development prospects, including the Dombey gas discovery. • 30-75% Cooper Energy interest. Offshore Otway Basin • Gas and gas liquids production from the Casino, Henry and Netherby fields. • Annie gas discovery and multiple exploration prospects. • Preparing for the Otway Phase Three Development. • 50% Cooper Energy interest in CHN • 10% Cooper Energy interest in VIC/L21 (Minerva) Melbourne • Engineering and technical support. Gippsland Basin • Gas and gas liquids production from the Sole field. • Manta and Gummy gas and gas liquids resource and multiple gas exploration prospects. • 100% Cooper Energy interest. Orbost Gas Processing Plant • Processing hub for offshore Gippsland Basin gas. • 100% Cooper Energy interest. Athena Gas Plant • Processing hub for Otway Basin gas. • 50% Cooper Energy interest 14 COOPER ENERGY ANNUAL REPORT 2023 COOPER ENERGY ANNUAL REPORT 2023 15 Key Results Financial • Record production, up 7.8% to 59.7 TJe/d (3.56 MMboe for the year) • Record operating cashflow, up 8.7% to $62.8 million • Record underlying EBITDAX, up 35.4% to $109.3 million Sales revenue ($ million) Operating cash flow ($ million) 205.4 196.9 62.8 57.8 48.1 131.7 75.5 78.1 20.5 8.1 FY19 FY20 FY21 FY22 FY23 FY19 FY20 FY21 FY22 FY23 Underlying EBITDAX ($ million) Net (debt)/cash ($ million) 109.3 89.0 80.7 34.3 29.6 30.0 -53.9 FY19 FY20 FY21 FY22 FY23 -97.8 -126.7 -80.9 FY19 FY20 FY21 FY22 FY23 Underlying net profit ($ million) Total equity ($ million) 13.3 14.4 -6.6 -5.6 498.4 496.9 433.7 351.1 325.8 FY19 FY20 -25.9 FY21 FY22 FY23 FY19 FY20 FY21 FY22 FY23 16 COOPER ENERGY ANNUAL REPORT 2023Operations & Reserves • Zero lost time injuries • More than 1,400 days LTI free • TRIFR below industry benchmark • Third consecutive year of record production Equity Safety – Total recordable injury frequency rate Share price (dollars per share at 30 June) 6.92 3.53 4.38 0.54 0.38 0.26 0.25 0.15 0.00 0.00 FY19 FY20 FY21 FY22 FY23 FY19 FY20 FY21 FY22 FY23 Production (TJe/d)¹ Basic earnings per share (cents per share at 30 June) 55.5 44.1 26.1 22.0 59.7 FY19 FY20 FY21 FY22 FY23 -0.7 -0.6 -1.8 -2.6 FY19 FY20 FY21 FY22 FY23 -5.3 Proved and Probable Reserves (PJe)² Market capitalisation ($ million at 30 June) 322 305 288 875.6 242 222 610.0 583.1 424.1 394.7 FY19 FY20 FY21 FY22 FY23 FY19 FY20 FY21 FY22 FY23 ¹1 MMboe = 6.11932 PJe ²As announced to the ASX on 25 August 2023 17 COOPER ENERGY ANNUAL REPORT 2023Key Results (Continued) Gas & oil revenue Gas Total sales volume (PJ) Total revenue ($million) 2P Reserves (PJ)¹ Average realised price ($/GJ) Oil and condensate Total sales volume (kbbl)² Total revenue ($million) 2P Reserves (MMbbl)¹ Average realised price ($/bbl) FY23 21.4 184.0 217.2 8.59 FY23 91.5 13.0 0.8 136.59 ¹As announced to the ASX 25 August 2023 ²Changes to PEL92 crude oil marketing arrangements came into effect 1 July 2022 which impacts FY23 comparisons with FY22. FY23 production total 116.6 kbbls vs FY22 122.2 kbbls. Capital expenditure By activity ($million) Exploration & appraisal Development TOTAL By basin ($million) Gippsland Basin Otway Basin Cooper Basin Other TOTAL FY23 25.1 16.9 42.0 FY23 18.2 18.0 4.8 0.9 42.0 FY22 22.7 188.1 235.1 8.29 FY22 126.6 17.3 1.1 129.14 FY22 4.9 14.6 19.5 FY22 0.4 15.3 3.3 0.5 19.5 18 COOPER ENERGY ANNUAL REPORT 2023Reserves & Contingent Resources Reserves Cooper Energy’s 2P gas and oil Reserves at 30 June 2023 are assessed to be 36.3 MMboe (222.2 PJe)¹. The key factors contributing to the reduction in Reserves since 30 June 2022 include: • Production of 3.6 MMboe in FY23 • Upward revisions of 0.5 MMboe (2P) in the offshore Otway through production performance and lower Athena turn-down rates • Downward revisions of 0.2 MMboe (2P) in the onshore Cooper Basin through reclassification of some projects from Undeveloped to Contingent and revised field limits ¹The conversion factor of 1 PJ = 0.163417 MMboe has been used to convert from sales gas (PJ) to oil equivalent (MMboe). The conversion factor 1 MMbbls = 6.11932 PJe has been used to convert oil (MMbbls) and condensate (MMbbls) to gas equivalent (PJe). Reserves at 30 June 2023¹ Category 1P Proved 2P Proved and Probable 3P Proved, Probable and Possible Dev. Undev. Sales gas (PJ) Oil + cond (MMbbl) Total (MMboe)² ³ 148.6 0.3 24.6 3.3 0.0 0.6 ¹As announced to the ASX on 25 August 2023 Total 151.9 0.4 25.2 Dev. Undev. 214.7 0.8 35.9 2.5 0.0 0.5 Total 217.2 0.8 36.3 Dev. Undev. 297.1 1.1 49.7 2.6 0.1 0.5 Total 299.7 1.2 50.2 ²Reserves exclude Cooper Energy’s share of future fuel usage. Totals may not reflect arithmetic addition due to rounding. The Reserves information displayed should be read in conjunction with the information in the Notes on calculation of Reserves and Contingent Resources provided in this document. ³ The conversion factor of 1 PJ = 0.163417 MMboe has been used to convert from sales gas (PJ) to oil equivalent (MMboe). Year-on-year movement in Reserves Category Reserves at 30 June 2022¹ FY23 production² Revisions/acquisitions Reserves at 30 June 2023³ Unit MMboe MMboe MMboe MMboe Proved and Probable 2P Reserves Cooper Otway Gippsland Total 1.1 (0.1) (0.2) 0.8 3.7 (0.6) 0.5 3.6 34.7 (2.8) 0.0 39.5 (3.6) 0.3 31.9 36.3 ¹As announced to the ASX on 22 August 2022 ²Production from 1 July 2022 to 30 June 2023 ³As announced to the ASX on 25 August 2023. Totals may not reflect arithmetic addition due to rounding. 19 COOPER ENERGY ANNUAL REPORT 2023Reserves & Contingent Resources (Continued) Gummy Contingent Resources² slightly offset by minor project and field-life timing related changes in the Cooper and Otway Basins. Contingent Resources Cooper Energy’s 2C Contingent Resources at 30 June 2023 have increased by 11.5 MMboe since 30 June 2022 to 48.4 MMboe (295.9 PJe)¹. The increase comes primarily from the new booking of ¹The conversion factor of 1 PJ = 0.163417 MMboe has been used to convert from sales gas (PJ) to oil equivalent (MMboe). The conversion factor 1 MMbbls = 6.11932 PJe has been used to convert oil (MMbbls) and condensate (MMbbls) to gas equivalent (PJe). ²As announced to the ASX on 25 August 2023 Contingent Resources at 30 June 2023¹ Category 1C 2C 3C Gas (PJ) Oil/Cond (MMbbl Total (MMbbl) Gas (PJ) Oil/Cond (MMbbll) Total (MMbbl) Gas (PJ) Oil/Cond (MMbbl) Total (MMbbl) Basin Gippsland 100.9 Otway Cooper Total² 42.8 0.0 143.8 2.5 0.0 0.3 2.9 19.0 198.9 7.0 0.3 64.8 0.0 26.4 263.7 4.9 0.1 0.3 5.3 37.4 10.7 0.3 365.0 84.1 0.0 9.7 0.1 0.5 48.4 449.0 10.3 69.3 13.9 0.5 83.7 ¹As announced to the ASX on 25 August 2023 ²Totals may not reflect arithmetic addition due to rounding. The Contingent Resources information displayed should be read in conjunction with the information in the Notes on calculation of Reserves and Contingent Resources provided in this document. Year-on-year movement in Contingent Resources Category Contingent Resources at 30 June 2022¹ Revisions Contingent Resources at 30 June 2023² Unit MMboe MMboe MMboe 1C 23.7 2.7 26.4 2C 36.9 11.5 48.4 3C 55.3 28.4 83.7 ¹As announced to the ASX on 22 August 2022 ²As announced to the ASX on 25 August 2023. Totals may not reflect arithmetic addition due to rounding. The Contingent Resources information displayed should be read in conjunction with the information in the Notes on calculation of Reserves and Contingent Resources provided in this document. 20 COOPER ENERGY ANNUAL REPORT 2023Notes on calculation of Reserves and Contingent Resources Cooper Energy prepares its petroleum Reserves and Contingent Resources in accordance with the definitions and guidelines in the Society of Petroleum Engineers (SPE) 2018 Petroleum Resources Management System (PRMS). The estimates of petroleum Reserves and Contingent Resources contained in this Reserves statement are as at 30 June 2023. The Company is not aware of any new information or data that materially affects the estimates of reserves and contingent resources, and the material assumptions and technical parameters underpinning the estimates continue to apply and have not materially changed. Unless otherwise stated, all references to Reserves and Contingent Resource quantities in this document are net to Cooper Energy. Cooper Energy has completed its own estimation of Reserves and Contingent Resources for its operated Otway and Gippsland Basin assets. Elsewhere, Reserves and Contingent Resource estimations are based on assessment and independent views of information provided by the permit operators (Beach Energy Limited for PEL 92). Reference points for Cooper Energy’s petroleum Reserves and Contingent Resources and production are defined points where normal operations cease, and petroleum products are measured under defined conditions prior to custody transfer. Fuel, flare and vent consumed prior to the reference point is excluded. Petroleum Reserves and Contingent Resources are prepared using deterministic, with support from probabilistic, methods. The Reserves and Contingent Resources estimate methodologies incorporate a range of uncertainty relating to each of the key reservoir input parameters to predict the likely range of outcomes. Project and field totals are aggregated by arithmetic summation by category. Aggregated 1P and 1C estimates may be conservative and aggregated 3P and 3C estimates may be optimistic due to the effects of arithmetic summation. Throughout this announcement, totals may not exactly reflect arithmetic addition due to rounding. The conversion factor of 1 PJ = 0.163417 MMboe has been used to convert from sales gas (PJ) to oil equivalent (MMboe). Condensate and crude oil are converted at 1bbl = 1 boe. The conversion factor 1 MMbbls = 6.11932 PJe has been used to convert oil (MMbbls) and condensate (MMbbls) to gas equivalent (PJe). Reserves Under the SPE PRMS 2018, “Reserves are 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 Otway Basin totals comprise the arithmetically aggregated project fields (Casino, Henry and Netherby). The Cooper Basin totals comprise the arithmetically aggregated PEL 92 fields. The Gippsland Basin totals comprise Sole Reserves only. Contingent Resources Under the SPE PRMS 2018, “Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by application of development projects, but which are not currently considered to be commercially recoverable owing to one or more contingencies”. The Contingent Resources assessment includes resources in the Gippsland, Otway and Cooper Basins. Qualified petroleum Reserves and Resources evaluator statement The information contained in this report regarding Cooper Energy’s Reserves and Contingent Resources is based on, and fairly represents, information and supporting documentation reviewed, prepared by, or under the supervision of, Mr Andrew Thomas who is a full-time employee of Cooper Energy Limited holding the position of General Manager Exploration, Subsurface & Projects. Mr Thomas holds a Bachelor of Science (Hons), is a member of the American Association of Petroleum Geologists and the Society of Petroleum Engineers, is qualified in accordance with ASX listing rule 5.41, and has consented to the inclusion of this information in the form and context in which it appears. 21 COOPER ENERGY ANNUAL REPORT 2023Review of operations Safety Detailed information regarding Cooper Energy’s safety performance is provided in the 2023 Sustainability Report. The 2023 Sustainability Report was published at the time of this Annual Report and can be viewed and downloaded from the Company’s website. Safety metrics Hours worked Recordable incidents Lost-time injuries (LTI) LTI frequency rate¹ Total recordable injury frequency rate (TRIFR)² Industry TRIFR³ ¹Per million hours worked FY23 228,482 FY22 220,238 1 0 0 4.38 5.68 0 0 0 0.00 6.91 ²TRIFR is recordable injuries (medical treatment injuries + restricted work/transfer case + lost time injuries + fatalities) per million hours worked. Calculated on a rolling 12-month basis ³Industry TRIFR is the NOPSEMA benchmark for offshore Australian operations; data is updated 6-monthly; published at www.nopsema.gov.au Production Cooper Energy achieved record annual gas and oil production of 21.8 PJe (3.56 MMboe) in FY23, mainly due to increasing gas production from the Sole field in the Gippsland Basin. Production by basin at 30 June 2023¹ Gas (PJ) Oil & Cond. (kbbl) Total (PJe) Gas (PJ) Oil & Cond. (kbbl) Total (PJe) FY23 FY22 Gippsland Basin Otway Basin Cooper Basin² TOTAL 17.2 3.9 - 21.1 - 3.6 116.6 120.1 17.2 3.9 0.7 21.8 15.2 4.3 - 19.5 - 3.0 122.2 125.2 15.2 4.3 0.7 20.2 ¹MMboe = 6.11932 PJe ²FY22 oil production figures may vary compared to previously reported data as a result of production allocation reconciliations. Gippsland Basin Cooper Energy is the operator and 100% interest holder for all its Gippsland Basin interests. As at 30 June 2023, these interests comprised: • VIC/L32, which contains the Sole gas and gas liquids field; • VIC/RL13, VIC/RL14 and VIC/RL15, which contains the Basker, Manta and Gummy (BMG) gas and liquids field (these retention leases also hold legacy infrastructure associated with the BMG oil project); • VIC/RL16, which contains the shut-in Patricia-Baleen gas field and infrastructure which connects to the OGPP; and • exploration permits VIC/P72, VIC/P75 and VIC/P80 Acquisition and integration of the Orbost Gas Processing Plant The OGPP, located 14 kilometres from Orbost, Victoria, is now fully owned and operated by Cooper Energy, having been acquired in July 2022. This facility processes the gas extracted from the Sole field, with the final product sold into the Southeast Australian gas market via the Eastern Gas Pipeline. Cooper Energy's acquisition of OGPP was announced on June 20, 2022 and the transaction was finalised on July 28, 2022. Following the acquisition, a transitional services agreement (TSA) was established with the previous owner, APA Group. Under this arrangement, APA Group continued to operate OGPP on behalf of Cooper 22 COOPER ENERGY ANNUAL REPORT 2023Energy until the major hazard facility license officially transferred to Cooper Energy on May 22, 2023. During this transitional period, plant performance experienced instability, resulting in lower processing rates than initially projected. Despite specific performance-based incentives being included as part of the acquisition, the threshold triggers for these incentives were not met and as such none were payable to the previous owner. The total cost of acquiring the plant amounts to $270 million on an undiscounted basis, including deferred payments of $40 million and $20 million in late July 2023 and late July 2024, respectively. The Orbost performance improvement plan, which has been underway in parallel with the transfer of operatorship workstream, is now being accelerated under Cooper Energy’s control, with specific tasks identified and being tested, targeting incremental increases to average processing rates. The great majority of this activity does not involve significant capital costs. BMG abandonment The BMG abandonment project in the Gippsland Basin involves decommissioning seven wells, using the Helix Q7000 abandonment vessel. In FY23, key milestones achieved include detailed Gippsland Basin planning, equipment procurement, contract awards for support vessels and services, engineering work finalisation, readiness reviews, and pre-abandonment programme planning. The pre-abandonment programme was completed in July 2023. The project aims to complete well abandonments in the coming months, with future work required to remove the remaining flowlines and subsea infrastructure by December 31, 2026, complying with regulatory requirements. Exploration During FY23, the Company focused on boosting the potential for a future Manta Hub development, covering VIC/RL13, VIC/RL14, VIC/RL15, and VIC/ P80. New 3D seismic data was obtained for these areas in Q1 FY23, enhancing the understanding of existing fields and providing opportunities for deeper exploration. An update on the prospective resource potential of the Manta Hub was announced to the ASX on 15 May 2023. The combined mean unrisked prospective resource potential from Manta Deep and Gummy Deep (VIC/RL13), Chimaera East (VIC/RL15) and Wobbegong (VIC/P80) is 1.3 Tcf of natural gas and 30 MMbbl of condensate. Melbourne VICTORIA Orbost E A STERN GAS PIPEL I N E Orbost Gas Processing Plant Lakes Entrance VIC/P72 (100%) Sweetlips Moonﬁsh Snapper Marlin Barracouta VIC/P75 (100%) Veilﬁn VIC/RL16 (100%) Patricia- Baleen Longtom Sunﬁsh Tuna Moby Judith Kipper Scallop Grunter Batﬁsh Angelﬁsh Flounder Fortescue To Sydney To Sydney Plan area TA VIC/P80 (100%) Sole Wobbegong VIC/L32 (100%) Manta Manta Deep Chimaera VIC/RL15 (100%) Chimaera East Chimaera East Basker Gummy Gummy Deep VIC/RL13 (100%) VIC/RL14 (100%) Luderick Bream 0 20 kilometres Gippsland_160 Mackerel Blackback Kingﬁsh Cooper Energy tenement Gas field Oil field Gas pipeline Oil pipeline Prospect 23 COOPER ENERGY ANNUAL REPORT 2023Review of operations (Continued) Otway Basin (offshore) The Company’s interests in the offshore Otway Basin as at 30 June 2023 comprised: • a 50% interest in and operatorship of production licences VIC/L24 and VIC/L30 containing the producing Casino, Henry and Netherby gas and gas liquids fields, with the remaining 50% interest held by Mitsui E&P Australia and its associated entities (“Mitsui”); • a 50% interest in and operatorship of production licences VIC/L33 and VIC/L34 containing part of the Black Watch and Martha gas fields, with the remaining 50% interest in these production licences held by Mitsui; • a 50% interest in and operatorship of exploration permit VIC/P44 containing the undeveloped Annie gas discovery, with the remaining 50% interest held by Mitsui; • a 100% interest in and operatorship of exploration permit VIC/P76; • a 50% interest in and operatorship of AGP (onshore Victoria), which is jointly owned with Mitsui and which processes gas and gas liquids from the Casino, Henry and Netherby gas fields; and • a 10% non-operated interest in production licence VIC/L22, which holds the shut-in Minerva gas field, with Woodside Energy the operator and 90% interest holder. Exploration A prospective resource update for six prospects (Elanora, Heera, Isabella, Juliet, Nestor and Pecten East) was announced on 9 February 2022. These prospects all show strong seismic amplitude support for the presence of gas and are located close to existing production infrastructure. There has been a total of 17 exploration wells drilled with seismic amplitude support in the offshore Otway Basin to date, across all operators, of which 16 have been successful. Work continued during FY23 to progress drilling options for testing the gas potential of these exploration prospects in conjunction with OP3D. Otway Phase 3 Development The OP3D project is the cornerstone of the next phase of Otway growth and provides an opportunity to tie back new resources to existing gas processing infrastructure at AGP, which has ~150 TJ/d of total capacity and current utilisation of ~25 TJ/d. It was planned that OP3D would move to FID in FY23, however joint venture alignment, together with the Federal Government’s gas market intervention, impacted the timeframe for decisions on the project. The Company nevertheless completed the OP3D FEED workstreams in H2 FY23, based on a three well development plan; this work having commenced in early FY23. To enable future OP3D drilling, Cooper Energy has worked with other operators in the region to collectively secure the services of a drilling rig. The drilling schedule is expected to commence in Q3 FY25. Cooper Energy has one firm well expected to be drilled in FY26 and options to drill exploration and/or development wells commencing in circa late FY26 or FY27. OP3D is expected to be a multi-well development that could include drilling the Nestor, Juliet and/ or Elanora prospects in addition to an Annie development. The project is positioned to re-start and proceed to sanction as soon as conditions permit, most particularly Otway joint venture partner support, along with our other FY24 business priorities. 24 COOPER ENERGY ANNUAL REPORT 2023Otway Basin (offshore) Otway Basin (onshore) The Company’s interests in the onshore Otway Basin as at 30 June 2023 comprised: • a 30% interest in PEL 494, PRL 32 and PEL 680 in South Australia, with the remaining interests held by the operator, Beach Energy; • a 50% interest in PEP 168 in Victoria, with the remaining interest held by the operator, Beach Energy; and • a 75% interest in PEP 171 in Victoria, with the remainder held by operator Vintage Energy Limited. Exploration In PEL 494 the Dombey 3D seismic survey acquisition was completed in March 2022. The surveyed area is located approximately 15 kilometres west of Penola and covers 165 square kilometres. The 3D seismic data was processed during FY23, with final data available for interpretation in early FY24. Assessments of the commercial potential and future development of the Dombey gas field, and further exploration drilling, will be evaluated during FY24. Additionally, existing 3D seismic surveys in PEP 168 were reprocessed in FY23. The new data has improved the seismic quality compared to the legacy dataset. Interpretation of the data will be undertaken in H1 FY24, with new interpretation informing the exploration strategy in the permit, including future exploration drilling. In PEP 171, which covers the Victorian side of the Penola trough, progress has been made in stakeholder engagement in advance of 100 square kilometres of 3D seismic survey acquisition. The anticipated timing to acquire this 3D data is currently during the 2024/2025 summer and aligned with other operators in the region to reduce costs. 25 COOPER ENERGY ANNUAL REPORT 2023Otway Basin (onshore) PEL 92 operations, Cooper Basin 26 COOPER ENERGY ANNUAL REPORT 2023Development First oil from the Bangalee field came online in February 2023 from the Bangalee-1 well, with initial 30-day average gross rates in line with expectations. Horizontal development wells were drilled in the Rincon and Callawonga oil fields in Q3 FY23. Rincon-4 and Callawonga-23 successfully targeted the undeveloped McKinlay Formation. Rincon-4 came online in June 2023 and Callawonga-23 came online subsequent to year end. Cooper Basin The Company’s interests in the Cooper Basin as at 30 June 2023 comprised: • a 25% interest in PRLs 85-104 (formerly PEL 92) with the remaining interests held by the operator, Beach Energy The sale of PRL’s 231-233, PRL 237, PRL’s 207-209 (formerly PEL 100) and PRL’s 183-190 (formerly PEL 110) to Bass Oil Limited (“Bass”), for $0.65 million was completed on 1 August 2022. Exploration No exploration wells were drilled in PRL’s 85-104 during FY23. Integration of the 2022 exploration drilling results has been completed, including the Bangalee-1 new field discovery. Work has progressed to define the 2023 exploration and appraisal programme, with exploration drilling likely to commence in the first half of FY24. Cooper Basin e g d e Permia n Rincon North Rincon 140° AAAAAA A RRRRRRR R RRRRRRRRRRRRRRRR RR R A W A H P A T C HHH H GGGGG G UUUU U O O R R TT T T Plan area E E G G RI DII RI D TAS GGGGGG MMM IMM G M I Callawonga Bangalee Elliston Parsons Perlubie Germein Butlers Sellicks Windmill Christies Silver Sands Lycium Hub HHHHH H O U GG TR O U G Cooper Energy tenement TRTT RI Gas field REE Oil field M EMM Gas pipeline APP PPPPP Oil pipeline NNNNNNNNNAAANNN NAPPAM ERRI PRLs 85 to 104 (25%) (ex PEL 92) MOOMBA 0 10 20 30 kilometres Cooper 99 27 COOPER ENERGY ANNUAL REPORT 2023Portfolio Cooper Energy Exploration & Production Tenements Gippsland Basin State Victoria Tenement Interest Location Area (km²) Operator Activity VIC/P72 VIC/P75 VIC/P80 VIC/RL13 (Basker-Manta-Gunny) VIC/RL14 VIC/RL15 VIC/RL16 (Patricia-Baleen) 100% 100% 100% 100% 100% 100% 100% Offshore Offshore Offshore Offshore Offshore Offshore 271 808 676 67 67 67 Cooper Energy Exploration Cooper Energy Exploration Cooper Energy Exploration Cooper Energy Retention Cooper Energy Retention Cooper Energy Retention Offshore 135 Cooper Energy Retention VIC/L32 (Sale) 100% Offshore 203 Cooper Energy Production Otway Basin State Tenement Interest Location Area (km²) Operator Activity South Australia PEL 494 Victoria PEL 680 PRL 32 PEP 168 PEP 171 VIC/P44 VIC/P76 VIC/L22 (Minerva) VIC/L24 (Casino) VIC/L30 (Henry & Netherby)) VIC/L33 VIC/L34 30% 30% 30% 50% 75% 50% 100% 10% 50% 50% 50% 50% Onshore Onshore Onshore Onshore 1,277 1,929 37 795 Beach Energy Exploration Beach Energy Exploration Beach Energy Retention Beach Energy Exploration Onshore 1,974 Vintage Energy Exploration Offshore Offshore Offshore Offshore Offshore 603 162 58 201 201 Cooper Energy Exploration Cooper Energy Exploration Woodside Energy Production Cooper Energy Production Cooper Energy Production Offshore 126 Cooper Energy Production Offshore 6 Cooper Energy Production Cooper Basin State Tenement Interest Location Area (km²) Operator Activity South Australia PPL 204 (Sellicks) PPL 205 (Christies-Silver Sands) PPL 220 (Callawonga) PPL 224 (Parsons) PPL 245 (Butlers) PPL 246 (Germein) PPL 247 (Perlubie) PPL 248 (Rincon) PPL 249 (Ellison) PPL 250 (Windmill) ex-PEL 92¹ 25% 25% 25% 25% 25% 25% 25% 25% 25% 25% 25% Onshore Onshore Onshore Onshore Onshore Onshore Onshore Onshore Onshore Onshore 2.0 4.3 5.5 1.8 2.1 0.1 1.5 2 0.8 0.6 Beach Energy Production Beach Energy Production Beach Energy Production Beach Energy Production Beach Energy Production Beach Energy Production Beach Energy Production Beach Energy Production Beach Energy Production Beach Energy Production Onshore 1,889.3 Beach Energy Exploration ¹ex-PEL 92 consists of PRL’s 85.86.87.88.89.90.92.93.94.95.96.97.98.99.100.101,102,103 and 104 28 COOPER ENERGY ANNUAL REPORT 2023Orbost Gas Processing Plant 29 COOPER ENERGY ANNUAL REPORT 2023Directors CHAIRMAN Mr John C. CONDE AO B.Sc. B.E(Hons), MBA INDEPENDENT NON-EXECUTIVE DIRECTOR Appointed 25 February 2013 MANAGING DIRECTOR AND CEO Ms Jane L. NORMAN B.Sc.,B.Eng.(Hons) PGDip GAICD Appointed 20 March 2023 Experience and expertise Mr Conde has extensive experience in business and commerce and in chairing high profile business, arts and sporting organisations. Previous positions include non-executive director of BHP Billiton (ASX:BHP), Chairman of Bupa Australia, Chairman of Pacific Power (the Electricity Commission of NSW), Chairman of the Sydney Symphony Orchestra, director of AFC Asian Cup, Chairman of Events NSW, President of the National Heart Foundation and Chairman of the Pymble Ladies’ College Council. Current and other directorships in the last 3 years Mr Conde is Chairman of The McGrath Foundation (since 2013 and director since 2012). He is also President of the Commonwealth Remuneration Tribunal (since 2003) and Chairman of Dexus Wholesale Property Fund (DWPF) (since 2020). Mr Conde is former Deputy Chairman of Whitehaven Coal Limited (ASX:WHC) (2007-2022) and former director of Dexus Property Group (ASX:DXS) (2009–2020). Special responsibilities Mr Conde is Chairman of the Board of Directors. Effective 19 August 2021 he is also a member of the People & Remuneration Committee and is the Chairman of the Governance & Nomination Committee. Experience and expertise Ms Norman has worked and studied in Australia and the UK and brings 30 years of industry experience in the energy markets. She began her career with Shell International Exploration & Production as a Process Engineer in operations and then as a Commercial Advisor in The Hague, Aberdeen and London. Subsequently, in London, Jane held corporate finance and equity capital markets roles with Cazenove & Co (now J.P. Morgan Cazenove) and Goldman Sachs. Ms Norman returned to Australia to join Santos where she held senior commercial, corporate strategy and Executive Committee roles. She led major strategic initiatives at Santos and played a key role in Santos’ growth strategy, in particular the merger with Oil Search. During her time at Santos Ms Norman helped drive the transformation of company performance, helping to establish the growth strategy focused on cash generation and shareholder returns and, more recently, the company’s energy transition strategy. Ms Norman holds a Bachelor of Science (Pure Mathematics and Chemistry) and Bachelor of Chemical Engineering (Hons) from the University of Sydney and a Graduate Diploma in Management and Economics of Natural Gas (Distinction) from the University of Oxford. Ms Norman is a Graduate of the Australian Institute of Company Directors. Current and other directorships in the last 3 years Ms Norman is a director of the wholly owned subsidiaries of Cooper Energy Limited and is on the Board of the Australian Petroleum Production and Exploration Association (since 2023). Special responsibilities Ms Norman is Managing Director and CEO. She is responsible for the day-to-day leadership of Cooper Energy, and is the leader of the Executive Leadership Team. 30 COOPER ENERGY ANNUAL REPORT 2023INDEPENDENT NON-EXECUTIVE DIRECTOR INDEPENDENT NON-EXECUTIVE DIRECTOR Mr Timothy G. BEDNALL LLB (Hons) Appointed 31 March 2020 Experience and expertise Mr Bednall is a highly experienced and respected corporate lawyer and law firm manager. He is a partner of King & Wood Mallesons (KWM), where he specialises in mergers and acquisitions, capital markets and corporate governance, representing public company and government clients. Mr Bednall has advised clients in the oil and gas and energy sectors throughout his career. Mr Bednall was the Chairman of the Australian partnership of KWM from January 2010 to December 2012, during which time the merger of King & Wood and Mallesons Stephen Jaques was negotiated and implemented. He was also Managing Partner of M&A and Tax for KWM Australia from 2013 to 2014, and Managing Partner of KWM Europe and Middle East from 2016 to 2017. He was General Counsel of Southcorp Limited (which became the core of Treasury Wine Estates Limited) from 2000 to 2001. Current and other directorships in the last 3 years Mr Bednall is a board member of the National Portrait Gallery Foundation (since 2018) and a director of Pooling Limited (since 2017). Special responsibilities Effective 19 August 2021 Mr Bednall is a member of the Audit Committee, the People & Remuneration Committee and the Governance & Nomination Committee. Ms Victoria J. BINNS B. Eng (Mining – Hons 1), Grad Dip SIA, FAusIMM, GAICD Appointed 2 March 2020 Experience and expertise Ms Binns has over 35 years’ experience in the global resources and financial services sectors including more than 10 years in executive leadership roles at BHP and 15 years in financial services with Merrill Lynch Australia and Macquarie Equities. During her career at BHP, Ms Binns’ roles included Vice President Minerals Marketing, leadership positions in the metals and coal marketing business, Vice President of Market Analysis and Economics and was a member of the first BHP Global Inclusion and Diversity Council. Prior to joining BHP, Ms Binns held a number of board and senior management roles at Merrill Lynch Australia including Managing Director and Head of Australian Research, Head of Global Mining, Metals and Steel, and Head of Australian Mining Research. She was also co-founder and Chair of Women in Mining and Resources Singapore. Current and other directorships in the last 3 years Ms Binns is currently a non-executive director of Evolution Mining (ASX:EVN) (since 2020) and Sims Limited (ASX:SGM) (since 2021). She is also a non-executive director of the Carbon Market Institute and a member of the J.P. Morgan Australia & NZ Advisory Council. Special responsibilities Effective 19 August 2021 Ms Binns is the Chairman of the Audit Committee and is a member of the Risk & Sustainability Committee. 31 COOPER ENERGY ANNUAL REPORT 2023Directors (Continued) INDEPENDENT NON-EXECUTIVE DIRECTOR INDEPENDENT NON-EXECUTIVE DIRECTOR Ms Giselle M. COLLINS B. Ec, CA GAICD Appointed 19 August 2021 Experience and expertise Ms Collins has broad executive and director experience across finance, treasury and property disciplines. Ms Collins is also active with not-for-profit organisations and has a strong interest in sustainability across many of her involvements. Ms Collins’ executive positions included General Manager Property, Treasury and Tourism of NRMA, Chief Executive Officer, Property and General Manager Finance with the Hannan Group, and Senior Manager, Audit Services with KPMG Switzerland. Current and other directorships in the last 3 years Ms Collins is currently Chairman of AMP Limited’s listed managed investment schemes (since 2020), a trustee director of the Royal Botanic Gardens and Domain Trust (since 2019), non-executive director of Generation Development Group (since 2018), Chairman of Hotel Property Investments Limited (ASX:HPI) (Chairman since July 2022 and director since 2017) and Chairman for Indigenous Business Australia in The Darwin Hotel Pty Limited (since 2014). Ms Collins is a former non-executive director and Chairman of the following companies: Aon Superannuation (2016-2017), The Travelodge Hotel Group (2009-2013), The Heart Research Institute Limited (2003-2011) as well as a non-executive director of Generation Life (2018–2021) and Peak Rare Earths Limited (ASX:PEK) (2021–2023). Special responsibilities Effective 19 August 2021 Ms Collins is a member of the Audit Committee and the Risk & Sustainability Committee. Ms Elizabeth A. DONAGHEY B.Sc., M.Sc. INDEPENDENT NON-EXECUTIVE DIRECTOR Appointed 25 June 2018 Experience and expertise Ms Donaghey brings over 30 years’ experience in the energy sector including technical, commercial, and executive roles in EnergyAustralia, Woodside Energy and BHP Petroleum. Ms Donaghey’s experience includes non-executive director roles at Imdex Ltd (an ASX-listed provider of drilling fluids and downhole instrumentation), St Barbara Ltd (a gold explorer and producer), and the Australian Renewable Energy Agency. She has performed extensive committee roles in these appointments, serving on audit and compliance, risk and audit, technical and regulatory, remuneration and health and safety committees. Current and other directorships in the last 3 years Ms Donaghey is currently a non-executive director of the Australian Energy Market Operator (AEMO) (since 2017) and a non-executive director of Ampol Limited (ASX: ALD) (since 2021). Special responsibilities Effective 19 August 2021 Ms Donaghey is a member of the Risk & Sustainability Committee, the People & Remuneration Committee and the Governance & Nomination Committee. Effective 23 June 2023 Ms Donaghey is the Chairman of the Risk & Sustainability Committee. 32 COOPER ENERGY ANNUAL REPORT 2023INDEPENDENT NON-EXECUTIVE DIRECTOR RETIRED MANAGING DIRECTOR Mr Jeffrey W. SCHNEIDER B.Com INDEPENDENT NON-EXECUTIVE DIRECTOR Appointed 12 October 2011 Mr David P. MAXWELL M.Tech, FAICD MANAGING DIRECTOR Appointed 12 October 2011 Retired 20 March 2023 Experience and expertise Mr Schneider has over 30 years of experience in senior management roles in the oil and gas industry, including 24 years with Woodside Energy. He has extensive corporate governance and board experience as both a non-executive director and chairman in resources companies. Current and other directorships in the last 3 years Mr Schneider does not currently hold any other directorships. Special responsibilities Effective 19 August 2021 Mr Schneider is Chairman of the People & Remuneration Committee and a member of the Governance & Nomination Committee. Experience and expertise Mr Maxwell is a leading oil and gas industry executive with more than 25 years in senior executive roles with companies such as BG Group, Woodside Energy and Santos. Mr Maxwell led many large commercial, marketing and business development projects. Prior to joining Cooper Energy Mr Maxwell worked with the BG Group, where he was responsible for all commercial, exploration, business development, strategy and marketing activities in Australia and led BG Group’s entry into Australia and Asia including a number of material acquisitions. Mr Maxwell has served on a number of industry association boards, government advisory groups and public company boards. Current and other directorships in the last 3 years Mr Maxwell was on the board of the Australian Petroleum Production & Exploration Association (2018-2023). Until Mr Maxwell’s retirement from Cooper Energy he was a director of the Company’s wholly owned subsidiary companies. Special responsibilities Prior to his retirement, Mr Maxwell was Managing Director. He was responsible for the day-to-day leadership of Cooper Energy and was the leader of the Executive Leadership Team. 33 COOPER ENERGY ANNUAL REPORT 2023Directors Directors (Continued) (Continued) Executive Leadership Team MANAGING DIRECTOR AND CEO Ms Jane L. NORMAN B.Sc.,B.Eng.(Hons) PGDip GAICD Ms Norman’s biography is shown in the Director’s section of the report. RETIRED INDEPENDENT NON-EXECUTIVE DIRECTOR Mr Hector M. GORDON B.Sc. (Hons). INDEPENDENT NON-EXECUTIVE DIRECTOR 26 June 2012 – 23 June 2017 NON-EXECUTIVE DIRECTOR Appointed 24 June 2017 Retired 23 June 2023 Experience and expertise Mr Gordon is a geologist with over 40 years’ experience in the upstream petroleum industry, primarily in Australia and Southeast Asia. He joined Cooper Energy in 2012, initially as Executive Director – Exploration & Production and subsequently moved to his position as non-executive director in 2017. Mr Gordon was previously Managing Director of Somerton Energy until it was acquired by Cooper Energy in 2012. Previously he was an Executive Director with Beach Energy Limited, where he was employed for more than 16 years. In this time Beach Energy experienced significant growth and Mr Gordon held a number of roles including Exploration Manager, Chief Operating Officer and, ultimately, Chief Executive Officer. Current and other directorships in the last 3 years Mr Gordon is a Non-Executive Director of Bass Oil Limited ASX: BAS (since 2014). Special responsibilities Prior to his retirement, Mr Gordon was the Chairman of the Risk & Sustainability Committee and a member of the Audit Committee. 34 COOPER ENERGY ANNUAL REPORT 2023CHIEF FINANCIAL OFFICER Mr Daniel YOUNG B. Com (Hons), MBA (Hons), CA, CFA GENERAL MANAGER COMMERCIAL & DEVELOPMENT Mr Eddy GLAVAS B. Acc. FCPA, MBA Mr Young joined Cooper Energy in May 2022. Mr Young is an energy professional with over 25 years of experience in Australia, Asia, and Europe. Mr Young joined Cooper Energy from Jadestone Energy plc where he held the role of Chief Financial Officer for over five years, based in Singapore. He also held the role of Executive Director with Jadestone. Prior to Jadestone, Mr Young was Head of APAC Consulting for Wood Mackenzie and earlier worked for 13 years in J.P. Morgan’s investment banking coverage/ mergers & acquisitions group in Europe and Asia, most recently as head of energy coverage in Southeast Asia and South Asia. After completing his undergraduate studies, Mr Young joined Deloitte where he qualified as a Chartered Accountant. Mr Young is also a CFA® charterholder. Mr Glavas joined Cooper Energy in August 2014 and has more than 20 years of experience in business development, finance, commercial, portfolio management and strategy, including 18 years in the oil and gas sector. Prior to joining Cooper Energy, he was employed by Santos as Manager Corporate Development with responsibility for managing multi- disciplinary teams tasked with mergers, acquisitions, partnerships and divestitures. Prior roles within Santos included: Finance Manager WA and NT, where Mr Glavas was a member of the leadership team that managed a large asset portfolio; corporate roles in strategy and planning; and operational, commercial and finance roles for Santos’ Cooper Basin assets. 35 COOPER ENERGY ANNUAL REPORT 2023Executive Leadership Team (Continued) GENERAL MANAGER EXPLORATION, SUBSURFACE & PROJECTS Mr Andrew THOMAS B. Sc. (Hons) HEAD OF OPERATIONS TASKFORCE Mr Nathan CHILDS B. Chem. Eng. (Hons) Mr Thomas is a successful and experienced geoscientist who has been involved with Australian and international gas and oil exploration and development projects for over 30 years. He has experience in a wide range of onshore and offshore basins in Australia, Asia and Africa. Prior to joining Cooper Energy, Mr Thomas was employed by Newfield Exploration in the roles of Southeast Asia New Ventures Manager and Exploration Manager for offshore Sarawak and was a key person in the team that successfully negotiated Newfield’s entry into Malaysia in 2004. Through the efforts of the teams he led, Newfield built a substantial portfolio of permits in Malaysia and made several significant oil and gas discoveries before being divested to SapuraKencana in 2014. Mr Thomas’s previous employers include Santos Limited, Gulf Canada and Geoscience Australia. He is a member of the American Association of Petroleum Geologists and a member of the Society of Petroleum Engineers. Mr Childs has over 25 years of experience in the gas and oil industry, having held line, technical, engineering and executive management roles. Before joining Cooper Energy in October 2019 as Head of Engineering and Planning, he was Santos's Vice President of Production Midstream. He worked through several roles at Santos across plant and process operations; engineering; production optimisation; asset management; commercial business development; integrity, and reliability. While working for Santos, Nathan made several strategic changes, including lowering operating costs, improving asset performance, increasing production, delivering $50 million of transformation initiatives to improve free cash flow and implementing Operations Discipline. Nathan began his career with Rio Tinto in research and technology development. He later worked at ExxonMobil's refining and supply business after graduating with first-class honours from Adelaide University with a Bachelor of Engineering- Chemical. 36 COOPER ENERGY ANNUAL REPORT 2023CHIEF ADVISOR & GENERAL MANAGER STRATEGY COMPANY SECRETARY AND GENERAL COUNSEL Ms Ying LUO B. Eng. (Hons), B. Sc. (Hons), MBA, Grad Cert. Ms Nicole ORTIGOSA BA LLB (Hons), Grad Dip Legal Practice Prior to joining Cooper Energy she worked for top tier law firms across Australia, including Clifford Chance and Minter Ellison. Nicole’s experience covers all legal, corporate, and commercial aspects of the business, including joint ventures, gas sales, infrastructure, environment, regulatory, procurement, mergers and acquisitions, corporate governance and compliance. Nicole started at Cooper Energy in 2017 and prior to becoming General Counsel & Company Secretary was the Legal Manager. Amongst other matters, she has advised the company on the development of the Sole gas field, the acquisition of the Athena Gas Plant and associated infrastructure and the acquisition of the Orbost Gas Processing Plant and associated onshore and offshore pipeline infrastructure. She holds a Bachelor of Laws with Honours from the University of Adelaide, and a Graduate Diploma in Legal Practice from the Law Society of South Australia. Ms Luo has almost 15 years of experience working in the energy sector in onshore gas, LNG and hydrogen. She began her career as a Graduate Mechanical Engineer with Santos. She progressed through several roles over the following decade including Production Engineer, and Operations Engineer where she implemented solutions to design and operability issues identified during the commissioning and start-up of the GLNG Project upstream wells and facilities. Ying also worked in the Corporate Strategy and Planning team, providing oil, LNG and domestic gas market analysis, supporting the development of Santos’ 10-year strategic plan. Her last four years with Santos were as the Project and Strategy Lead for the Energy Solutions division. Ying developed, implemented, and maintained the Energy Solutions strategy and led a portfolio of emissions reduction, renewable integration and hydrogen projects. Most recently she worked as the Senior Adviser, Hydrogen Development for the Australian Gas Infrastructure Group where she led the development of Australia’s largest renewable hydrogen production and blending project in Albury-Wodonga, Victoria. Ying has a Bachelor of Mechanical Engineering with First Class Honours; Bachelor of Science (Mathematics, Computer Science) with First Class Honours; Graduate Certificate in Energy and Resources Policy and Practice and an MBA. She was awarded the Sir John Monash Scholarship for Excellence at Monash University and the Exceptional Young Women in Resources from the South Australian Chamber of Mines and Energy. 37 COOPER ENERGY ANNUAL REPORT 2023Executive Leadership Team (Continued) GENERAL MANAGER PEOPLE & REMUNERATION Mr Ashley HAREN Dip. Bus. (HR/IR) GENERAL MANAGER HSEC & TECHNICAL SERVICES Mr Iain MACDOUGALL B. Sc. (Hons) Mr Haren joined Cooper Energy in January 2021. He has more than 25 years of experience in human resource management in corporate and operational roles. Mr Haren has worked for global and domestic publicly listed and private entities within the professional services, beverage, retail, mining, and gas and oil sectors. Prior to Cooper Energy, Mr Haren was the Global Leader People & Culture – Operations with Woods Bagot and spent nine years with Pernod Ricard Winemakers including five years as HR Director – Australia. His previous appointments included General Manager HR for Australian Leisure & Hospitality, Group HR Manager at Foster’s Limited and various HR roles with Mt Isa Mines (Australia and Argentina) and Santos Limited. Mr MacDougall’s career in the upstream petroleum exploration and production business spans more than 30 years, prior to which he worked in the nuclear power industry and in automotive powertrain research and development. He gained extensive experience with international oilfield services company Schlumberger, with operational and management assignments in Australia, Asia, the UK North Sea, Europe, West Africa and the Middle East. Since 2001, he has been based in Australia, initially with independent Operator Stuart Petroleum as Production and Engineering Manager and subsequently as acting CEO prior to the takeover of Stuart Petroleum by Senex Energy. Mr MacDougall is an alumnus of Manchester University in the UK and of the INSEAD Business School in France. 38 COOPER ENERGY ANNUAL REPORT 2023Key Performance Indicators Operational Production 2P Proved and Probable Reserves Wells drilled Exploration wells spudded Reserves replacement ratio¹ Financial Sales revenue Other income Net profit / (loss) before tax Net profit (loss) after tax Cash and cash equivalents Other financial assets FY15 FY16 FY17 FY18 FY19 FY20 FY21 FY22 FY23 PJe MMboe # # % 2.9 3.1 9 4 2.8 3.0 1 - 5.9 11.7 9.1 52.4 8.0 52.7 9 1 4 2 - - 9.5 49.9 18 4 16.1 47.1 20.3 39.5 21.8 36.3 1 - 2 2 2 - 333% 18% 768% 2380% (206%) (65%) 17% (65%) 24% $ million $ million 39.1 1.9 27.4 0.9 EBITDA $ million (58.4) (37.4) $ million (18.8) (26.0) (7.0) 39.1 1.6 1.9 67.5 4.9 49.9 31.0 75.5 4.2 7.5 78.1 19.8 (75.2) 131.7 205.4 196.9 7.2 23.5 - - 44.9 20.7 (13.2) (110.0) (33.5) (22.7) (104.7) $ million (63.5) (34.8) (12.3) 27.0 (12.1) (86.0) (30.0) (10.6) (68.5) $ million 39.4 49.8 147.5 236.9 164.3 131.6 91.3 247.0 77.1 $ million 1.9 1.0 0.7 42.6 21.7 0.6 1.2 0.5 1.1 Working capital $ million 43.0 44.2 84.0 154.0 131.8 90.4 30.3 190.3 (121.8) Accumulated profit $ million (17.7) (52.6) (64.9) (37.9) (49.9) (136.0) (166.0) (177.5) (245.9) Franking credits $ million 43.7 Total equity $ million 103.9 42.9 91.6 42.9 42.9 42.9 42.9 42.9 42.9 42.9 285.0 443.9 433.7 351.1 325.8 498.4 496.9 Earnings per share cents (19.2) (10.1) (1.8) 1.8 (0.7) (5.3 ) (1.8) (0.6) (2.6) Return on shareholder funds Total shareholder return % % (46.7%) (38.0%) (6.5%) 7.4% (2.6%) (21.9%) (8.9%) (2.6%) (13.8%) (51.5%) (12.2%) 72.7% 6.0% 40.3% (30.6%) (30.7%) (5.8%) (38.8%) Average oil price $/bbl 85.48 60.75 61.89 99.61 106.19 83.75 79.56 129.46 136.59 Capital at 30 June Share price Issued shares Market capitalisation $ # 0.245 0.215 0.380 0.385 0.540 0.375 0.260 0.245 0.150 331.9 435.2 1,140.2 1,601.1 1,621.6 1,621.6 1,631.0 2,379.8 2,631.5 $ million 81.4 93.6 433.3 616.4 875.5 608.1 424.1 583.1 394.7 Shareholders # 5,103 4,931 6,292 6,622 6,758 8,094 9,355 9,198 9,039 ¹The annual reserve replacement ratio is calculated based on the net 1P reserve additions for the year divided by annual production. 39 COOPER ENERGY ANNUAL REPORT 202340 COOPER ENERGY ANNUAL REPORT 2023FINANCIAL REPORT 30 June 2023 COOPER ENERGY LIMITED And its controlled entities. ABN 93 096 170 295 41 COOPER ENERGY ANNUAL REPORT 2023Table of Contents Operating and Financial Review .......................... 43 Funding and Risk Management Directors’ Statutory Report .................................. 60 Remuneration Report .......................................... 64 Consolidated Statement of Comprehensive Income ................................... 88 Consolidated Statement of Financial Position............................................. 89 Consolidated Statement of Changes in Equity ........................................... 90 Consolidated Statement of Cash Flows ...................................................... 91 Notes to the Consolidated Financial Statements ........................................... 92 17. Interest bearing loans and borrowings ...... 115 18. Net finance costs ...................................... 115 19. Contributed equity and reserves ............... 116 20. Financial risk management ....................... 117 Group Structure 21. Interests in joint arrangements .................. 121 22. Investments in controlled entities .............. 122 23. Parent entity information ........................... 123 Other Information Group Performance 24. Commitments for expenditure ................... 124 1. Segment reporting ........................................ 95 25. Contingent liabilities .................................. 124 2. Revenues and expenses ............................... 97 26. Share based payments ............................. 124 3. Income tax .................................................... 99 27. Related party disclosures ......................... 126 4. Earnings per share ..................................... 102 28. Remuneration of Auditors ......................... 126 29. Events after the reporting period .............. 126 Directors’ Declaration ........................................ 127 Independent Auditor’s Report to the Members of Cooper Energy Limited .................................. 128 Auditor’s Independence Declaration to the Directors of Cooper Energy Limited .................. 135 Securities Exchange and Shareholder Information .................................... 136 Abbreviations and Terms ................................... 138 Corporate Directory ........................................... 139 Working Capital 5. Cash and cash equivalents and term deposits .............................................. 103 6. Trade and other receivables ....................... 104 7. Prepayments .............................................. 104 8. Inventory ..................................................... 104 9. Trade and other payables ............................ 104 Capital Employed 10. Property, plant and equipment .................. 105 11. Intangible assets ....................................... 105 12. Exploration and evaluation assets ............ 106 13. Gas and oil assets .................................... 107 14. Impairment ................................................ 108 15. Provisions ................................................. 111 16. Leases ...................................................... 113 42 COOPER ENERGY ANNUAL REPORT 2023Operating and Financial Review For the year ended 30 June 2023 OPERATIONS Cooper Energy Limited (“Cooper Energy” or the “Company”) generates revenue from the production of gas and condensate in the Otway and Gippsland Basins, and from the production of oil in the Cooper Basin. The Company’s current operations and interests include: • offshore gas and gas liquids production in the Gippsland Basin, Victoria, from the Sole gas field; • offshore gas and gas liquids production in the Otway Basin, Victoria, from the Casino, Henry and Netherby gas fields; • onshore oil production in the Western Flank of the Cooper Basin, South Australia; • • • • the Orbost Gas Processing Plant (“OGPP”) onshore Gippsland Basin, Victoria; the Athena Gas Plant (“AGP”) onshore Otway Basin, Victoria; the Annie gas discovery in the offshore Otway Basin; the Manta and Gummy gas and liquids fields in the Gippsland Basin; and • additional exploration and appraisal prospects in the onshore and offshore Otway, offshore Gippsland and Cooper Basins. Health, safety and environment Zero lost time injuries (“LTI”) and one medical treatment injury (“MTI”) were recorded for the twelve months to 30 June 2023. The medical treatment injury occurred at AGP in January, where a contractor suffered a lacerated finger which required stitches at the local medical clinic. Consequently, the total recordable injury frequency rate (“TRIFR”) was 4.38 injuries per million hours worked, compared to 0.00 in the previous twelve months to 30 June 2022. This remains below the industry benchmark of 5.68¹ injuries per million hours worked. There were two reportable environmental incidents during the period. Both were as a result of emissions exceedances at AGP above the limits specified in the EPA licence conditions. The first, in March 2023, involved emissions of carbon monoxide from a thermal oxidizer exhaust. The second, in May 2023, involved emissions of benzene from the same unit. The events were assessed as not giving rise to actual or potential harm to either human health or to the environment and were reported to the Victorian EPA as required under regulations. Both matters have been remedied with a revision to operating procedures. The Company is the operator of all its offshore activities, including the OGPP and AGP, and non-operator of all its onshore activities. Orbost Gas Processing Plant integration Workforce At 30 June 2023, the Company had 128.9 full time equivalent (“FTE”) employees and 24.4 FTE contractors, compared with 89.9 FTE employees and 13.3 FTE contractors at 30 June 2022. Employee numbers increased in FY23 as a result of the transition of the OGPP into Cooper Energy operations, and the associated increase in engineering resources required to support both gas plants. Changes to the organisational structure were made in Q4 FY23, shortly after the commencement of the new Managing Director and CEO, centred around the formation of an operations taskforce. This taskforce ensures a single point of accountability for operations, maintenance, and engineering to ensure an integrated approach to operations of both OGPP and AGP, and to the performance improvement plan for OGPP. Contractors are engaged via third parties in South Australia, Western Australia and Victoria, and numbers fluctuated in line with project requirements, including the OGPP integration work which was finalised in Q4 FY23. As of 30 June 2023, all contractors engaged by Cooper Energy were contracted via third party providers. The OGPP is located approximately 14 kms from Orbost, Victoria and is 100% owned and operated by Cooper Energy, following the acquisition of the plant in July 2022. The plant processes gas from the offshore Sole field, in the Gippsland Basin, and connects to the Southeast Australian market via the Eastern Gas Pipeline. Cooper Energy announced the acquisition of the OGPP on 20 June 2022, with the transaction completing on 28 July 2022, at which point Cooper Energy and the seller, APA Group, commenced a transitional services agreement (“TSA”). The seller continued to operate the OGPP, pursuant to the TSA, on behalf of Cooper Energy, until the plant’s major hazard facility licence transferred to Cooper Energy on 22 May 2023. A largely contract workforce was engaged to complete the integration workstreams including the major hazard facility licence transfer, assurance reviews, operational readiness, and additional environmental and pipeline licence transfers. During the transition to Cooper Energy operatorship, plant performance was unstable, and as a result average processing rates were less than anticipated. The transaction to acquire the plant included performance- ¹NOPSEMA industry rolling 12-month TRIFR to 30 June 2023 43 COOPER ENERGY ANNUAL REPORT 2023Operating and Financial Review For the year ended 30 June 2023 based incentives for the seller, however the performance hurdles were not met and as a result no performance payments are payable to the seller. The total consideration paid for the plant is $270 million, which includes two deferred payments of $40 million and $20 million to be paid in late July 2023 and late July 2024 respectively. Reserves and Contingent Resources Proved and Probable Reserves (2P) at 30 June 2023 are assessed to be 36.3 MMboe compared with 39.5 MMboe at 30 June 2022. Changes to 2P Reserves for FY23 include production of -3.6 MMboe and 2P Reserves revisions of +0.3MMboe. Contingent Resources (2C) at 30 June 2023 are assessed to be 48.4 MMboe compared with 36.9 MMboe at 30 June 2022. Details of Reserves and Contingent Resources and the movement from the previous year are available in the ASX announcement titled ‘Reserves and Contingent Resources at 30 June 2023’, released on 25 August 2023. Reserves and Contingent Resources As at 30 June 2023¹ Gippsland Basin Otway Basin Cooper Basin Total Cooper Energy Proved and Probable Reserves (2P) Contingent Resources (2C) Gas PJ 195.2 22.0 0.0 217.2 Oil & condensate MMbbl Total MMboe² 0.0 0.0 0.8 0.8 31.9 3.6 0.8 36.3 Gas PJ 198.9 64.8 0.0 263.7 Oil & condensate MMbbl 4.9 0.1 0.3 5.3 Total MMboe 37.4 10.7 0.3 48.4 ¹As announced on 29 August 2023. Totals may not reflect arithmetic addition due to rounding. The method of aggregation is by arithmetic sum by category. ² The conversion factor of 1 PJ = 0.163417 MMboe has been used to convert from sales gas (PJ) to oil equivalent (MMboe). Production Gas and oil production for FY23 was 3.56 MMboe, or 9,766 boe/d, 7.8% higher than the prior year, mainly due to increased gas production from Sole following improved performance at OGPP. Total gas production of 21.1 PJ, or 57.7 TJ/d, was 8.3% higher than the prior year. In the Gippsland Basin, increased Sole production and improved OGPP performance resulted in a 13.4% increase in gas production to 17.2 PJ. In the Otway Basin, natural field decline and processing interruptions at AGP contributed to a 9.5% decline in gas production to 3.9 PJ (net to Cooper Energy’s 50% share). Oil and condensate production was 120.1 kbbl, or 329 bbls/d (net to Cooper Energy), 4.1% lower than the prior year due to natural field decline in PEL 92 in the Cooper Basin. Production by product and basin is summarised in the following tables. Production Production by product Sales gas Oil and condensate² Total production Production by basin Gippsland Basin Sole: sales gas Otway Basin Casino Henry: sales gas Casino Henry: condensate Cooper Basin Oil¹ Total production PJ kbbl MMboe PJ PJ kbbl kbbl MMboe FY23 21.1 120.1 3.56 FY23 17.2 3.9 3.6 116.6 3.56 FY22 19.5 125.2 3.31 Change 8.3% (4.1%) 7.8% FY22 Change 15.2 4.3 3.0 122.2 3.31 13.4% (9.5%) 17.8% (4.6%) 7.8% ² FY22 oil production figures may vary compared to previously reported data as a result of production allocation reconciliations. 44 COOPER ENERGY ANNUAL REPORT 2023Operating and Financial Review For the year ended 30 June 2023 Reserves and Contingent Resources Orbost Gas Processing Plant The Gas Code aims to ensure that Australian East Coast gas users can contract for gas at reasonable prices and on reasonable terms. As noted above, while the acquisition of OGPP closed on 28 July 2022, APA continued to operate the plant until operatorship was transferred on 22 May 2023. OGPP achieved an average gas processing rate of 47.1 TJ/d during FY23 (FY22: 41.5 TJ/d), with rates largely dependent on the cycle time of the absorber cleans. The polishing unit had limited impact during the year, although showed promising signs with the plant able to achieve an average of 55.9 TJ/d for the month of September 2022 when the unit was online for the majority of the month. Although Sole gas production volume was 13.4% higher in FY23 versus FY22, for the majority of FY23 plant performance was below expectations. Average processing rates were hampered by regular plant trips, shutdowns and incidents of operator error. Performance continues to be impaired by foaming and fouling in the sulphur recovery unit’s two absorbers, which has constrained processing rates and required regular maintenance and cleaning. The Sole gas field continues to perform in line with expectations. Athena Gas Plant AGP achieved an average gas processing rate of 10.7 TJ/d during FY23 (FY22: 11.8 TJ/d), with rates impacted by unplanned downtime to the C701 export gas compressor resulting in 31 days of deferred production in H2 FY23. The investigation and remediation work to the compressor is believed to have successfully solved a long-standing systemic issue that has been present for over a decade. Well cycling operations were implemented throughout the year to optimise production from the CHN fields. Commercial Key commercial activities during the financial year are summarised below. Gas sales agreement In November 2022, Cooper Energy and AGL Energy Limited agreed to enter into a new long-term gas sales agreement (“GSA”) to supply up to 10 PJ of natural gas per annum, for a term of up to six years. The GSA volumes are anticipated to account for approximately 50% to 70% of the Cooper Energy share of Otway gas production from the commencement of production from the Otway Phase 3 Development (“OP3D”) project. The GSA is conditional on an affirmative final investment decision (“FID”) on OP3D. Government Mandatory Gas Code In July 2023 the Federal Government announced the release of a Mandatory Gas Code of Conduct (“the Gas Code”), legislated through the Competition and Consumer (Gas Market Code) Regulations 2023. Key elements of the Gas Code include: • a price cap of $12/GJ, subject to an exemptions framework; • information reporting obligations on the amount of uncontracted gas to be marketed and produced; and • minimum conduct and process standards for commercial negotiations. With annual production of less than 100 PJ, Cooper Energy qualifies as a small domestic supplier under the Gas Code and is therefore automatically exempt from the $12/GJ price cap for any gas sales from 2024 onwards. Foundational gas sales agreements to support the commercialisation of undeveloped gas are also exempt from the Gas Code’s expression of interest and offer timing provisions, which will ensure investment in new gas supply is not inadvertently discouraged. Other suppliers can seek a conditional Ministerial exemption from the price cap, for gas supply agreements, by making satisfactory ACCC and court-enforceable commitments. Cooper Energy’s future gas marketing activities are not expected to be materially impacted by complying with the Gas Code’s requirements. Changes to petroleum resource rent tax (“PPRT”) In early May, the Federal Government announced changes to PRRT, in response to the Treasury Gas Transfer Pricing Review together with the recommendations from the earlier 2018 Callaghan Review. Cooper Energy is largely unaffected by the PRRT changes. The key change, introducing a 90% cap on the use of deductions from 1 July 2023, applies tooffshore LNG projects only and hence does not impact Cooper Energy. The intention to legislate to exclude appraisal costs from the definition of exploration with effect from 2013, is consistent with the Company’s current practise. Regulatory reporting obligations During the period Cooper Energy commenced reporting of new information obligations under the National Gas Amendment (Market Transparency) Rule 2022. Cooper Energy is now subject to a suite of additional weekly and annual information reporting obligations to the Australian Energy Market Operator and the Australian Energy Regulator, including reserves and resource data, gas price assumptions and medium-term gas plant processing capacity outlooks. The Company regularly provides information to the ACCC, AEMO and AER, and monitors compliance with applicable regulatory reporting requirements. 45 COOPER ENERGY ANNUAL REPORT 2023Operating and Financial Review For the year ended 30 June 2023 Physical gas portfolio management During FY23 Cooper Energy continued to improve its physical gas portfolio management capability. a small number of external expert consultants, and does not involve significant capital costs. Exploration This capability enables the Company to deliver on sales obligations, manage operational and financial risk, and maximise total value, over both a short and long- term horizon. The FY23 exploration focus in the Gippsland Basin has been on adding further potential to a future Manta Hub development in VIC/RL13, VIC/RL14, VIC/RL15, and exploration permit VIC/P80. Cooper Energy’s physical gas portfolio management activities include the use of: • short-term third-party gas purchase and sale agreements; • buying and selling gas within the Victorian Declared Wholesale Gas Market; and • pipeline transport and park services. All customer nominations were met during the period, in line with contractual obligations. Cooper Oil processing and marketing arrangements Cooper Energy entered into a suite of revised commercial arrangements effective on 1 July 2022 with the Santos operated South Australia Cooper Basin joint venture providing for the processing and marketing of PEL 92 crude. The new commercial arrangements include a crude oil processing service agreement, a crude oil transportation agreement and a liquids aggregation agreement. The term of these three agreements run to 31 December 2023. Development, exploration and abandonment GIPPSLAND BASIN Cooper Energy is the operator and 100% interest holder for all its Gippsland Basin interests. As at 30 June 2023, these interests comprised: a) VIC/L32, which contains the Sole gas field; b) VIC/RL13, VIC/RL14 and VIC/RL15, which contains the Basker, Manta and Gummy (BMG) gas and liquids field (these retention leases also hold legacy infrastructure associated with the BMG oil project); c) VIC/RL16, which contains the shut-in Patricia-Baleen gas field and infrastructure which connects to the OGPP; and d) exploration permits VIC/P72, VIC/P75 and VIC/P80. The Orbost performance improvement plan, which has been underway in parallel with the transfer of operatorship workstream, is now being accelerated under Cooper Energy’s control, with specific tasks identified and targeting incremental increases to average processing rates. There are six major workstreams under the performance improvement plan, with work expected to occur throughout the remainder of calendar year 2023. The majority of this activity comprises internal costs, with New 3D seismic data acquired in 2020 covering VIC/ RL13, VIC/RL14, VIC/RL15 and VIC/P80 was licenced from CGG in Q1 FY23. The new seismic data has improved the structural definition of the existing BMG gas and oil fields and exploration prospectivity below and adjacent to existing fields. Future appraisal or development of existing fields can be combined with testing this deeper exploration potential. An update on the Prospective Resource potential of the Manta Hub in retention licences VIC/RL13, VIC/ RL14, VIC/RL15, and exploration permit VIC/P80 was provided on 15 May 2023. The combined mean unrisked Prospective Resource potential from Manta Deep and Gummy Deep (VIC/RL13), Chimaera East (VIC/RL15) and Wobbegong (VIC/P80) is 1.3 Tcf of natural gas and 30 MMbbl of condensate as announced to the ASX on 15 May 2023. BMG abandonment The BMG abandonment project in the Gippsland Basin involves decommissioning seven wells as a first phase, and subsequently the associated subsea infrastructure as a second phase. The Helix Q7000 abandonment vessel was contracted in September 2020 to perform the work. Key milestones achieved in the BMG abandonment project during FY23 include: • detailed planning and ordering of long lead equipment; • awarding contracts to support vessels and services; • finalising detailed engineering work including activity workshops with service contractors; • ‘readiness to operate’ assurance review; and • pre-abandonment programme planning for data gathering and equipment interface checks at the BMG well locations. The pre-abandonment programme was completed in July 2023. It is planned to complete the abandonment activities of the BMG wells by 31 December 2023 and remove the remaining infrastructure by 31 December 2026, in accordance with regulatory requirements. In June 2023, the Company provided an update on the cost estimates for the abandonment project, recognising industry inflation on supporting contracts such as support vessels, helicopters, rig work and other costs. The mid case cost to complete the well abandonment is estimated to be $193-$198 million on a 100% gross basis, with approximately $27.9 million of this incurred in FY23. 46 COOPER ENERGY ANNUAL REPORT 2023Operating and Financial Review For the year ended 30 June 2023 The recently completed BMG pre-abandonment work programme reduces risks on commencement when the Q7000 arrives on location. The mid case cost estimate incorporates contingencies for non-productive time and weather delays, as well as an additional general contingency. While the Company’s focus will be on executing the programme safely and within the minimum time possible, there remain certain risks, including variables outside of Cooper Energy’s control. These risks include delays to the receipt of the rig beyond the nominated window under the rig contract, greater than expected decommissioning work in the event that we are unable to complete the programme to NOPSEMA’s satisfaction, or other factors, that could raise the total cost above the mid-case. Cooper Energy continues to pursue its Victorian Supreme Court claim against PT Pertamina Hulu Energi (“Pertamina”) for Pertamina’s 10% share of the BMG decommissioning costs. These costs relate to decommissioning of the seven wells and related subsea infrastructure of the BMG oil project. Pertamina, via an Australian subsidiary, participated in the BMG oil project during its production life and Cooper Energy’s claim against Pertamina arises with respect to obligations under the withdrawal and abandonment provisions of the BMG joint operating and production agreement. OTWAY BASIN (OFFSHORE) The Company’s interests in the offshore Otway Basin as at 30 June 2023 comprised: a) a 50% interest in and operatorship of production licences VIC/L24 and VIC/L30 containing the producing Casino, Henry and Netherby gas fields, with the remaining 50% interest held by Mitsui E&P Australia and its associated entities (“Mitsui”); b) a 50% interest in and operatorship of production licences VIC/L33 and VIC/L34 containing part of the Black Watch and Martha gas fields, with the remaining 50% interest in these production licences held by Mitsui; c) a 50% interest in and operatorship of exploration permit VIC/P44 containing the undeveloped Annie gas discovery, with the remaining 50% interest held by Mitsui; d) a 100% interest in and operatorship of exploration permit VIC/P76; e) a 50% interest in and operatorship of AGP (onshore Victoria), which is jointly owned with Mitsui and processes gas from the Casino, Henry and Netherby gas fields; and f) a 10% non-operated interest in production licence VIC/L22, which holds the shut-in Minerva gas field, with Woodside Energy the operator and 90% interest holder. Exploration A Prospective Resource update for six prospects (Elanora, Heera, Isabella, Juliet, Nestor and Pecten East) was announced on 9 February 2022. These prospects all show strong seismic amplitude support for the presence of gas and are located close to existing production infrastructure. There has been a total of 17 exploration wells drilled with seismic amplitude support in the offshore Otway Basin to date, across all operators, of which 16 have been successful. Work continued during FY23 to progress drilling options for testing the gas potential of these exploration prospects in conjunction with OP3D. Development Otway Phase 3 Development Project The OP3D project is the cornerstone of the next phase of Otway growth and provides an opportunity to tie back new resources to existing gas processing infrastructure at AGP, which has ~150 TJ/d of total capacity and current utilisation of ~25 TJ/d. AGP is a strategically important piece of energy infrastructure; extrapolation from publicly available analogue gas plant costs in Australia suggests the estimated replacement cost of this plant is in the range of $450 - 800 million, if it were constructed today. Additionally, it is estimated that it would take at least five years of planning and construction timing to commission a plant of this scale in Victoria. It was planned that OP3D would move to FID in FY23, however joint venture alignment, together with the Federal Government’s gas market intervention, announced on 9 December 2022, and in particular the proposed mandatory code of conduct including pricing principles, impacted the timeframe for decisions on the OP3D project. The Company nevertheless completed the OP3D FEED workstreams based on a three well development plan in H2 FY23, which had commenced earlier in FY23. Resolution of the Federal Government’s gas market intervention is summarised in the Commercial section of this report. To enable future OP3D drilling, Cooper Energy has worked with other operators in the region to collectively secure the services of a drilling rig. In Q4 FY23 a binding award for the Transocean Equinox rig was agreed across a consortium of four separate operators including Cooper Energy. The consortium drilling schedule is expected to commence in Q3 FY25. Cooper Energy has one firm well expected to be drilled in H1 FY26 and options to drill exploration and/or development wells commencing in late FY26. OP3D is expected to be a multi-well development that could include drilling the Nestor, Juliet and Elanora prospects in addition to an Annie development. In the same rig campaign, Woodside Energy, the Operator of VIC/L22 (Cooper Energy share 10%), will plug up to four subsea wells at the Minerva gas field as soon as practicable before end of FY25. OP3D is positioned to re-start and proceed to sanction as soon as conditions permit, most particularly Otway 47 COOPER ENERGY ANNUAL REPORT 2023Operating and Financial Review For the year ended 30 June 2023 joint venture partner support, substantial progress of the BMG abandonment programme, and higher average processing rates and cash generation at OGPP as a result of the performance improvement plan. Otway growth will be funded from organic cash generation, supported by the existing committed senior secured bank facility as well as the $120 million accordion facility. OTWAY BASIN (ONSHORE) The Company’s interests in the onshore Otway Basin as at 30 June 2023 comprised: a) a 30% interest in PEL 494, PRL 32 and PEL 680 in South Australia, with the remaining interests held by the operator, Beach Energy; b) a 50% interest in PEP 168 in Victoria, with the remaining interest held by the operator, Beach Energy; and c) a 75% interest in PEP 171 in Victoria, with the remainder held by operator Vintage Energy Limited. Exploration In PEL 494 the Dombey 3D seismic survey acquisition was completed in March 2022. The surveyed area is located approximately 15 kilometres west of Penola and covers 165 square kilometres. The 3D seismic data was processed during FY23, with final data available for interpretation in early FY24. Assessments of the commercial potential and future development of the Dombey gas field, and further exploration drilling, will be evaluated during H1 FY24. Existing 3D seismic surveys in PEP 168 were reprocessed in FY23. The new data has improved the seismic quality compared to the legacy dataset. Interpretation of the data will be undertaken in H1 FY24. The new interpretation will inform the exploration strategy in the permit, including future exploration drilling. In PEP-171, which covers the Victorian side of the Penola trough, progress has been made in stakeholder engagement in advance of 100 square kilometres 3D seismic survey acquisition. The anticipated timing to acquire this 3D data is currently during the 2024/2025 summer and aligned with other operators in the region to reduce costs. Onshore Otway well abandonment PRL 32 permit was renewed until May 2028. The remaining activity is abandonment of three wells (Patrick-1, Hollick-1 and Jacaranda-2) that is anticipated in calendar 2026. COOPER BASIN The Company’s interests in the Cooper Basin as at 30 June 2023 comprised: a) a 25% interest in PRLs 85-104 (formerly PEL 92) with the remaining interests held by the operator, Beach Energy. The sale of PRL’s 231-233, PRL 237, PRL’s 207-209 (formerly PEL 100) and PRL’s 183-190 (formerly PEL 110) to Bass Oil Limited (“Bass”), for $0.65 million was completed on 1 August 2022. The sale to Bass demonstrates Cooper Energy’s ongoing focus on portfolio optimisation and divesting non-core assets. Cooper Energy’s primary focus remains on commercialising cost-competitive gas resources for Southeast Australia. Exploration No exploration wells were drilled in PRL’s 85-104 during FY23. Integration of the 2022 exploration drilling results has been completed, including the Bangalee-1 new field discovery. Work has progressed to define the 2023 exploration and appraisal programme, with exploration drilling likely to commence in the first half of FY24. Development First oil from the Bangalee field came online in February 2023 from the Bangalee-1 well, with initial 30-day average gross rates in line with expectations at around 670 bbls/d. Horizontal development wells were drilled in the Rincon and Callawonga oil fields in Q3 FY23. Rincon-4 and Callawonga-23 successfully targeted the undeveloped McKinlay Formation. Rincon-4 came online in June and initially produced 300-350 bbls/d (gross 100%), although constrained by trucking capacity. Callawonga-23 came online subsequent to year end, with initial production estimated at approximately 875 bbls/d (gross 100%). Other Activities Vietnam nature-based carbon project The Company announced on 30 November 2022 its participation in a A$1.1 million private-public-NGO partnership in nature-based carbon offset projects in Vietnam, intended to generate tradeable carbon credits. The Department of Foreign Affairs and Trade is providing funding and support to the project through the Business Partnerships Platform. Contributions have been provided by Cooper Energy and other implementation partners. The pilot phase is focused on development of a circa 700-hectare reforestation carbon project scheduled for implementation in 2025. Subject to a detailed feasibility study, the project has the potential to involve more than one million trees being planted, which would generate approximately 16,000 tonnes of offsets per annum for a crediting period of 25 years. The initiative has the potential for significant scale expansion within Vietnam, supporting Cooper Energy’s commitment to remain carbon neutral for Scope-1, Scope-2 and relevant Scope-3 emissions.¹ ¹Cooper Energy has been certified by Climate Active as a carbon neutral organisation for its Scope-1, Scope-2 and relevant Scope-3 emissions (embedded energy and business travel). See 2023 Sustainability Report for further information. 48 COOPER ENERGY ANNUAL REPORT 2023Operating and Financial Review For the year ended 30 June 2023 FINANCIAL PERFORMANCE All numbers in tables in the Operating and Financial Review have been rounded and are expressed in Australian dollars, except where noted otherwise. Some total figures may differ insignificantly from totals obtained from the arithmetic addition of the rounded numbers presented. In order to provide a more meaningful comparison of operating results between periods, the calculation of underlying EBITDAX and of underlying net profit/ (loss) after tax includes adjustments for items which are considered unrelated to the Company’s underlying operating performance. Movement in underlying EBITDAX 30 June 2022 Vs 30 June 2023 Underlying EBITDAX and underlying net profit/(loss) after tax are not defined measures under International Financial Reporting Standards and are not audited. For that reason, reconciliations of underlying EBITDAX and of underlying net profit/(loss) after tax are included at the end of this review. Cooper Energy recorded FY23 underlying EBITDAX of A$109.3 million, 35.4% higher than FY22 underlying EBITDAX of A$80.7 million. There are several drivers behind the change, which are summarised in the chart below. A$ Million 80.7 109.3 u-EBITDAX FY22 Lower Sales Volumes Fewer third party gas purchases Higher gas price realisations Lower tolling costs Higher production costs Lower crude oil revenue Higher G&A Other u-EBITDAX FY23 The principal factors which contributed to the movement in underlying EBITDAX between the periods included: • • lower gas sales revenue of A$3.5 million attributed to lower sales volumes compared to the previous year (3.59 PJ in FY23, versus 3.83 PJ in FY22), partially offset by higher realised gas prices across the portfolio (A$8.59/GJ in FY23, versus A$8.30/GJ in FY22); third-party gas purchases and trading costs were lower by A$17.1 million in FY23 due to the higher processing rates at OGPP; • production expenses were higher by A$33.3 million in FY23, however more than offset by the A$54.0 million saving in tolling costs due to the cessation of tolling arrangements with APA following completion of the acquisition of OGPP in late July 2022; • lower crude oil sales revenue of A$5.0 million, due to lower volumes of lifted oil of 87.7 kbbls in FY23, versus 125.2 kbbls in FY22 and an increase in average price realisations to A$138.05/bbl in FY23 (FY22: A$129.46/bbl). Production at PEL92 averaged 329 bbls/d in FY23 (FY22: 343 bbls/d) which highlights the other key factor in FY23, namely, the one-off change in PEL92 crude oil marketing arrangements as of 1 July 2022, with revenue recognised upon sale ex-Port Bonython instead of at the inlet to the South Australia Cooper Basin joint venture facilities at Moomba; and • higher administration and other items of A$0.7 million. The underlying loss after tax (exclusive of the items noted below) was A$5.6 million compared with an underlying profit after tax of A$14.4 million in FY22. Factors driving the change, in addition to those listed above for underlying EBITDAX, included: • higher amortisation and depreciation of A$44.8 million of gas and oil assets and property, plant and equipment, primarily due to higher production, depreciation associated with OGPP and the reset of restoration provisions as at 30 June 2022; • higher net finance costs of A$12.9 million, mostly due to higher accretion expense of the Company’s restoration provisions (which were reset at 30 June 2022); and • higher tax benefit of A$8.9 million. The Company’s statutory loss after tax was A$68.5 million, which compares with a loss after tax of A$10.6 million recorded in FY22. The FY23 statutory loss included a number of significant items considered to fall 49 COOPER ENERGY ANNUAL REPORT 2023Operating and Financial Review For the year ended 30 June 2023 outside underlying operating performance, which affected the result by a total of A$62.9 million. These items comprise: • non-cash restoration expense of A$46.3 million resulting from a reassessment of the Patricia Baleen, BMG and Minerva Field decommissioning provisions; • a non-cash impairment expense of A$26.1 million in respect of the Casino Henry Netherby CGU; • OGPP acquisition costs, integration costs that were not capitalised, and reconfiguration and commissioning works under the TSA of A$6.2 million; • normalisation of the July APA toll of A$2.9 million; • leadership restructuring costs of A$2.7 million; • doubtful debts expense of A$2.8 million; • other expense of A$1.7 million in respect of the National Oil & Gas Australia Pty Ltd Commonwealth Government levy; and • tax impact of the above items of A$25.8 million. Accounting for the financing and acquisition of OGPP The acquisition of the OGPP completed in July 2022, alongside the institutional and retail equity offering and new underwritten revolving corporate debt facility. The accounting impacts of the transaction are as follows: • OGPP capitalised to property, plant and equipment at a value of A$374.0 million (including A$210.0 million of upfront consideration, A$58.1 million of deferred consideration and A$27.0 million of capitalised acquisition and transaction costs, and A$78.9 million in relation to the restoration obligations acquired); • deferred consideration of A$58.1 million recognised as trade payables (with A$40.0 classified as a current payable and A$19.3 million as non-current). The Company will not pay any of the up to A$60.0 million of additional performance linked incentive payments that were agreed last year; • transaction costs of A$15.1 million associated with the new debt facility are capitalised and net off against the current utilised amount. A$1.1 million of these costs are amortised to the income statement via the effective interest rate: and • gross new equity capital raised was A$244.0 million. After transaction costs of A$8.4 million, net cash proceeds were A$235.6 million. Of this, an after tax amount of A$179.5 million was recognised within reserves in equity in FY22, representing the institutional portion of the raise which was received by the Company on 30 June 2022. This was subsequently transferred to share capital in July 2023 with the issuance of the shares. The after tax retail portion of the raise of A$58.6 million was recognised in H1 FY23. Costs of A$1.5 million incurred in FY23 cannot be offset within share capital and are therefore included within the income statement. Financial Performance Production volume Sales volume Revenue Gross profit Underlying EBITDAX* Operating cash flow Underlying profit/(loss) before tax Underlying profit/(loss) after tax Reported loss after tax Cash, other financial assets and investments MMboe MMboe A$ million A$ million A$ million A$ million A$ million A$ million A$ million A$ million FY23 3.56 3.59 196.9 32.5 109.3 62.8 (41.8) (5.6) (68.5) 78.2 FY22 3.31 3.83 205.4 47.8 80.7 57.8 2.2 14.4 (10.6) 247.5 Change 0.25 (0.24) (8.5) (15.3) 28.6 5.0 (44.0) (20.0) (57.9) % 7.8% (6.3%) (4.1%) (32.0%) 35.4% 8.7% N/M N/M N/M (169.3) (68.4%) * Earnings before interest, tax, depreciation, amortisation, restoration, exploration and evaluation expense and impairment 50 COOPER ENERGY ANNUAL REPORT 2023Operating and Financial Review For the year ended 30 June 2023 Operating cashflows for the period were A$62.8 million in FY23, 8.7% higher than in FY22 of A$57.8 million. The main line items for operating cashflow comprised: • • cash generated from operations of A$96.7 million (FY22: A$82.5 million). The major drivers of the increase are explained above in relation to underlying EBITDAX, while noting that changes in working capital are captured in cash from operations whereas EBITDAX is prepared on an accruals basis; restoration costs of A$19.6 million (FY22: A$6.1 million), up mostly due to the increasing level of activity in the lead up to the wells abandonment activity at BMG in FY24; • petroleum resource rent tax (PRRT) payments of A$6.2 million (FY22 A$0.9 million), due to higher deductible expenditure in FY22; and • net interest paid of A$8.1 million ( FY22: A$9.2 million). Financing, investing and other cash flows for the period were A$233.7 million (FY22: A$96.4 million) and primarily included: • • the OGPP upfront acquisition cost of A$210.0 million, plus other acquisition and financing costs of A$27.0 million (FY22: A$6.5 million); remaining net proceeds from the equity issue, being the retail portion of the entitlement offer, of A$57.6 million (FY22: A$178.0 million being the institutional portion); • exploration, intangibles, development and property, plant and equipment costs of A$38.6 million, mainly in relation to the OP3D select phase, OGPP, Athena Gas Plant and general exploration and evaluation activity (FY22: A$20.8 million); • proceeds from held for sale assets of A$0.7 million (FY22: nil); • repayment of lease liability of A$1.3 million (FY22: A$1.1 million); • net repayment of borrowings of nil (FY22: A$60.0 million); • prepaid financing costs of A$15.1 million (FY22: nil), being the costs associated with the refinancing and expansion of the senior secured revolving credit facility; and • foreign exchange revaluation and other of A$1.0 million (FY22: A$1.8 million). Excluding the one-off impacts associated with the OGPP acquisition and financing, cash and cash equivalents increased by A$24.6 million over the period, as summarised in the following chart. 51 COOPER ENERGY ANNUAL REPORT 2023Operating and Financial Review For the year ended 30 June 2023 Movements in cash and cash equivalents 30 June 2023 vs 30 June 2022 A$ million A$ million Total cash and cash equivalents, other ﬁnancial assets and investments Total cash and cash equivalents, other ﬁnancial assets and investments 57.6 57.6 0.5 0.5 247.0 247.0 Jun-22 Jun-22 (210.0) (210.0) Restoration cash Restoration cash ﬂows primarily ﬂows primarily relate to costs relate to costs associated with associated with BMG BMG (19.6) (19.6) (6.2) (6.2) (8.1) (8.1) 96.7 96.7 (27.0) (27.0) (15.1) (15.1) OGPP Acquisition (194.5) OGPP Acquisition (194.5) 52.5 52.5 Operating Operating 62.8 62.8 Capex includes costs associated with OGPP transition & OP3D FEED Capex includes costs associated with OGPP transition & OP3D FEED (38.6) (38.6) 115.3 115.3 Total cash and Total cash and cash equivalents, cash equivalents, other ﬁnancial other ﬁnancial assets and assets and investments investments 78.2 78.2 0.7 0.7 (1.3) (1.3) 1.0 1.0 1.1 1.1 Other (38.2) Other (38.2) 77.1 77.1 Proceeds from equity issue Proceeds from equity issue OGPP purchase Stamp duty and acquisition costs OGPP purchase Stamp duty and acquisition costs Financing and other costs Financing and other costs Cash after OGPP acquisition Cash after OGPP acquisition Operations Operations Restoration Restoration PRRT PRRT Interest Interest Cash after OCF Cash after OCF Capex Capex Proceeds from held for sale assets Proceeds from held for sale assets Lease liabilities Lease liabilities FX & other FX & other Jun-23 Jun-23 Cash & cash equivalents Cash & cash equivalents Other ﬁnancial assets and investments Other ﬁnancial assets and investments 52 COOPER ENERGY ANNUAL REPORT 2023 COOPER ENERGY ANNUAL REPORT 2023 53 Operating and Financial Review For the year ended 30 June 2023 FINANCIAL POSITION Total equity Financial Position Total assets Total liabilities Total equity Net (debt)/ cash¹ A$ million A$ million A$ million A$ million FY23 FY22 Change % 1,344.4 1,200.0 144.4 12.0% 847.5 701.5 146.0 20.8% 496.9 498.4 (1.5) (0.3%) (80.9) 89.0 (169.9) N/M Total equity decreased by A$1.5 million from A$498.4 million to A$496.9 million. In comparing equity at 30 June 2023 to 30 June 2022, the key movements were: • higher contributed equity of A$238.4 million due to transfer of proceeds from the institutional portion of the June 2022 equity raise from reserves, shares issued under the non-institutional portion of the entitlement offer in July 2022 plus vesting of performance rights during the period; • lower reserves of A$171.6 million due to transfer of proceeds from the institutional portion of the June 2022 equity raise to share capital; and • higher accumulated losses of A$68.5 million due to the statutory loss for the period. ¹ Net debt above is based on drawn debt of A$158.0 million. Debt per Balance sheet is A$143.9 million which includes $A14.1million of prepaid financing costs. STRATEGY AND OUTLOOK Total assets Total assets increased by A$144.4 million from A$1,200.0 million at 30 June 2022 to A$1,344.4 million at 30 June 2023. At 30 June 2023, the Company held cash and cash equivalents of A$77.1 million and investments of A$1.1 million. Property, plant and equipment increased by A$321.1 million from A$59.2 million at 30 June 2022 to A$380.4 million at 30 June 2023, due to the acquisition of the OGPP, with the transaction closing for accounting purposes on 28 July 2022, offset by impairment of the Athena Gas Plant. Gas and oil assets decreased by A$59.5 million from A$595.4 million to A$535.8 million, mainly as a result of amortisation driven by production and impairment of the Casino Henry Netherby assets. Exploration and evaluation assets increased by A$19.7 million from A$164.9 million to A$184.6 million, as a result of general exploration and evaluation activity, offset by impairment of the Annie exploration asset. Total liabilities Total liabilities increased by A$146.0 million from A$701.5 million at 30 June 2022 to A$847.5 million at 30 June 2023. Provisions increased by A$107.0 million from A$476.6 million to A$583.6 million, primarily driven by the recognition of the OGPP restoration provision and a reset of certain other provisions. The sum of current and non-current trade and other payables increased by A$55.2 million year-on-year, with the majority of this increase due to the delayed purchase consideration of OGPP due to APA Group, which is $59.3 million inclusive of discounting. Cooper Energy remains focused on playing a pivotal role in Australia’s energy future, by commercialising gas for Australian customers. We are committed to delivering domestic gas to our customers, who include manufacturers, major energy generators and retailers including for gas-fired power generation. Gas fired power is a key established electricity generation technology that provides fast start dispatchable firming power to support an increasing percentage of variable renewables in the electricity market. We operate with an emphasis on health and safety, environmental and sustainability compliance, reliability and shareholder value. In FY24, our strategic imperatives are to: • improve the operating performance of OGPP to maximise production into the Southeast Australian gas market and capture high spot market prices; • execute BMG abandonment on schedule and on Budget; • reduce fixed costs across our business; • work to partner with others to unlock Otway growth opportunities; • progress exploration, appraisal and development activities within Cooper Energy’s existing portfolio of growth opportunities, across the Company’s twin gas hubs; and • maintain our voluntary organisational carbon neutral certified¹ position with an added focus on physical abatement opportunities to reduce the absolute quantum of our Scope-1 and Scope-2 emissions. ¹ Cooper Energy has been certified by Climate Active as a carbon neutral organisation for its Scope-1, Scope-2 and relevant Scope-3 emissions (embedded energy and business travel). See 2023 Sustainability Report for further information. 54 COOPER ENERGY ANNUAL REPORT 2023Operating and Financial Review For the year ended 30 June 2023 FUNDING AND CAPITAL MANAGEMENT At 30 June 2023, the Company had cash reserves of $77.1 million and drawn debt of $158.0 million. The Company has a reserves based lending debt facility with a committed limit of A$400.0 million (excluding a A$120.0 million accordion facility), to be used for general corporate purposes. Management plans to utilise the facility to part fund the BMG abandonment project as well as a portion of the planned OP3D development in the Otway Basin. The Company has additional liquidity of A$20.0 million through a working capital facility to be used for general business purposes, of which around A$7.7 million has been utilised in respect of bank guarantees as at 30 June 2023. The facility also includes an additional amount of up to $120.0 million, under an accordion facility, subject to certain terms and conditions. The Company’s liquidity position is illustrated in the following chart: Funding and liquidity A$ Million 158.0 20.0 120.0 400.0 7.7 77.1 Cash & cash equivalents 30/06/2023 RBL committed funding Drawn portion at 30/06/2023 Working capital facility Utilisation 30/06/2023 451.4 Additional accordian Adjusted subtotal including accordian 331.4 Cash & committed undrawn funding 30/06/2023 Further information is detailed in the Basis of preparation and accounting policies section of the Financial Statements. leadership team revise risk assessments and review risk management actions for corporate level risks on a regular basis. The Company continues to assess accretive funding options as it pursues growth opportunities. RISK MANAGEMENT The Company has an established risk management protocol that is applied at all organisational levels, and serves to identify and manage risk within the Company’s risk appetite. The Company’s management system is continually reviewed and revised to provide effective management of operational and business risks. The executive The non-financial internal audit program supports the risk management program by reviewing the effectiveness of key risk controls and advising on improvements. Corporate risk activities and internal audit outcomes are regularly reported to and discussed with the Risk & Sustainability Committee of the Board. This Committee oversees the risk and non-financial audit programs and provides guidance. 55 COOPER ENERGY ANNUAL REPORT 2023Operating and Financial Review For the year ended 30 June 2023 Risk Description Orbost Gas Plant performance BMG wells abandonment execution The OGPP is producing at below nameplate production capacity. Continuation of the under performance of the Thiopaq H2S removal process presents an ongoing production, revenue, and operating cashflow risk. Cooper Energy is progressing an improvement project targeting the Thiopaq process under performance, and specifically the impacts associated with sulphur deposition and fouling in the absorbers. Cooper Energy operates with a comprehensive range of operating and risk management plans and an enterprise-wide integrated management system to ensure safe and sustainable operations. The Helix Q7000 intervention vessel is scheduled to commence abandonment works at seven Basker and Manta field wells in H1 FY24. Risks associated with the execution of the abandonment campaign include safety and environmental incidents, unexpected technical well conditions that prolong abandonment activities, project delays due to regulatory and/or contractual uncertainty, and failure of critical equipment. Cooper Energy has a comprehensive approach to the management of health, safety and environmental. The company’s project management systems integrate technical and engineering requirements aimed at mitigating project execution risks. Actions taken to reduce execution risks during the abandonment programme include completion of an offshore pre-abandonment campaign prior to arrival of the Q7000, independent assessment of the abandonment programme by regulators and external auditors, completion of an abandon-well- on-paper exercise, and pre-operation readiness assessments of the Q7000 and key equipment. Health safety and environment The nature of Cooper Energy’s operations poses inherent risks to the health and safety of employees and contractors as well as posing a range of environmental risks. A major environmental incident could jeopardise Cooper Energy’s licence to operate, leading to delays, disruption and potentially interruption of the company’s activities. Cooper Energy has a comprehensive approach to the management of health, safety and environmental risks. The company’s management systems integrate technical and engineering requirements with management and mitigation of personal health and safety risks, process safety risks and environmental risks. JV partnership alignment The ability for Cooper Energy to execute growth activity in a joint venture (“JV”) can be impacted by the strategy and appetite for capital investment by its JV partner. The joint operating agreement (“JOA”) that covers the Company’s JV in the offshore Otway contains sole risk and voting provisions in scenarios where JV parties have different or misaligned objectives. Changes to restoration obligations/ provisions Cooper Energy has certain restoration obligations with respect to its exploration and development licences, including subsea wells, production facilities and related infrastructure. These liabilities are derived from legislative and regulatory requirements, which are subject to change. Cooper Energy’s balance sheet incorporates estimates for such decommissioning and abandonment activity, with those estimates included within provisions. Cooper Energy conducts a review of restoration provisions on a semi-annual basis. This includes a review of the assumptions included in the estimation, such as changes to the legislative and/or regulatory requirements for decommissioning and abandonment, future remaining reserves estimates, timing and costs and resultant production from the commercialisation of contingent resources, current prevailing market rates and costs to undertake decommissioning and abandonment activity, future inflation rates, and appropriate discount rates. Gas and oil reserves and estimates of contingent resources are expressions of judgement based on knowledge, experience and industry practice. Estimates may change and may change significantly, or become uncertain, when new information becomes available and/or there are material changes to circumstances which result in a change to plans. This may have a positive or negative effect on estimated restoration provisions. Changes to the estimate of restoration provisions are recognised in line with accounting standards. Restoration provisions are informed estimates, but there can be no assurance that the future actual costs associated with decommissioning and abandonment will not exceed the long-term provision quantum recognised to cover this activity. 56 COOPER ENERGY ANNUAL REPORT 2023Operating and Financial Review For the year ended 30 June 2023 Risk Description Positive cash generation and access to capital Cooper Energy undertakes significant capital expenditure to fund exploration, appraisal, development and restoration requirements. While Cooper Energy generates positive operating cashflow to reinvest into the business, it will also seek, from time to time, to access third-party capital to accelerate organic and inorganic growth options. Organic operating cashflow generation is dependent upon many variables, such as production rates including uptime, prevailing spot prices for uncontracted gas and global oil price benchmarks, operating costs, general and administration costs, taxation and foreign exchange rates. Spot gas prices are subject to fluctuations and are affected by numerous factors beyond the control of Cooper Energy. Cooper Energy monitors and analyses its gas and oil markets and seeks to reduce price risk where reasonable and practical. Gas price risk is assessed within the context of the Company’s ongoing modelling of the Southeast Australian energy market and through its gas contracting strategy, which prioritises long term agreements and appropriate indexation and price review clauses. There can be no assurance that sufficient organic operating cashflow generation and/or access to incremental third-party capital will be available on acceptable terms, or at all. Lower organic operating cashflow generation and/ or limitations on access to adequate incremental third-party capital could have a material adverse effect on the business, including the ability to commercialise discoveries and expand the Company’s operations, long term results from operations, financial conditions and prospects, and compliance with covenants under the existing bank facility. If Cooper Energy accesses further funding under the existing debt facility, Cooper Energy’s debt levels will increase. Consequently, there is a risk that Cooper Energy may be more exposed to risks associated with gearing and leverage. Failure to comply with the covenants of the debt facility could limit financial flexibility. It may enable the bank group to accelerate repayment of the Company’s debt obligations. Lower organic operating cashflows, whether as a result of a decline in commodity prices or otherwise, may also give rise to changes in the assumptions incorporated into the estimation of fair market values used to test the carrying value of Cooper Energy’s gas and oil assets Market intervention and legislative changes Cooper Energy operates in a highly regulated environment and complies with the law. Changes can prolong compliance, delay approvals and escalate costs, impacting the company’s financial position or expected financial returns. Federal or State Government intervention, legislative, policy or guideline changes can impact Cooper Energy’s operations and share value. Cooper Energy engages with Federal and State governments and regulators on a regular basis to maintain open channels of communication. Climate change & energy transition Cooper Energy recognises its activities may be subject to increasing regulation and costs associated with climate change and the management of carbon emissions. electricity) and relevant Scope-3 emissions (e.g. embedded energy and business travel), with a blend of Australian and international carbon credits. Risks are identified and managed in two broad categories: physical climate change risks, relating to direct impacts on the Company’s operations and energy transition risks, arising from the move to a lower carbon energy system. A comprehensive range of risks and opportunities associated with climate change is incorporated into company policy, strategy and risk management processes. Cooper Energy has taken a proactive stance since 2020 to voluntarily offset its Scope-1 (direct), Scope-2 (purchased The Company’s carbon neutral status¹ is certified by Climate Active, an initiative of the Australian Federal Government. For the avoidance of doubt, Cooper Energy does not offset downstream customer “Scope-3” emissions which arise primarily from processing, transmission, distribution and combustion of sold products. Cooper Energy is investigating opportunities to invest in carbon credit origination projects, both in Australia and overseas. Carbon credits allow us to mitigate the impact of our emissions now while taking cost effective action to reduce future emissions through various efficiency projects. 57 COOPER ENERGY ANNUAL REPORT 2023Operating and Financial Review For the year ended 30 June 2023 Risk Description Climate change & energy transition (Continued) In respect of energy transition risk, the Company’s core gas assets are resilient to the threat of demand loss from climate change. AEMO scenarios indicate that although gas demand may slowly reduce in Cooper Energy’s markets, gas supply is declining even faster in the Southern states of Australia, creating a significant supply- demand gap. This creates an opportunity for Cooper Energy to grow its business and to increase market share. Gas is expected to play a significant role through the energy transition in two key areas. First, as a conventional energy source for heating and industrial use, where limited cost effective or practical alternatives are available, and secondly, to provide firming of variable renewable power generation as the electricity network continues to decarbonise. The focus of the Company’s strategy on conventional gas production, located in Southeast Australia close to its market, is conducive to lower overall emissions intensity compared to more remote domestic gas sources or imported Liquefied Natural Gas (“LNG”) supply. The Company measures and publicly reports its emissions and emissions offsets to maintain its carbon neutral¹ position. These results, together with detail on climate change impacts, direct emissions reduction initiatives and its energy transition strategy are described in Cooper Energy’s annual Sustainability Report. Disclosures are aligned with the Taskforce on Climate related Financial Disclosures. See page 20 of the 2022 Sustainability Report for further information. AGP asset performance AGP, formerly named the Minerva Gas plant, was built by BHP in 2009, and was repurposed and renamed the Athena Gas Plant by Cooper Energy in 2020. Characterised as a mature asset, there are inherent risk associated with aging equipment nearing end of life. Sales gas and raw gas compression reliability, aging fixed equipment, and end of life control systems for the offshore wells presents an ongoing production, revenue, and operating cashflow risk. Cooper Energy has developed and is progressing strategies and actions to mitigate and minimise these risks. Cooper Energy operates with a comprehensive range of operating and risk management plans and an enterprise-wide integrated management system to ensure safe and sustainable operations. To the extent that it is reasonable and possible to do so, Cooper Energy mitigates the risk of loss associated with operating events through insurance. Cyber security Cooper Energy’s operations are and will continue to be reliant on various computer systems, data repositories and interfaces with networks and other systems. Failures or breaches of these systems (including by way of virus and hacking attacks) have the potential to materially and negatively impact Cooper Energy’s operations. Cooper Energy has barriers, continuity plans and risk management systems in place, however there are inherent limits to such plans and systems. Further, Cooper Energy has no control over the cyber security plans and systems of third parties which may interface with Cooper Energy’s operations, or upon whose services Cooper Energy’s operations are reliant. Access to skills and capabilities Cooper Energy relies on the ability to attract and retain people with the right skills, behaviors and capability to deliver both its base business and its growth opportunities. It also relies on skills and expertise provided through industry service providers for both onshore and offshore operations. Failure to access such capability and services may constrain the achievement of business objectives. Cooper Energy has established employment conditions and practices, incentives and workplace culture designed to attract and retain the skills and experience needed to deliver business objectives. We aim to appeal to a diverse group of individuals and ensure their inclusion in our ‘one team’ ethos as core personnel. Metrics are in place to monitor employee engagement, and these are regularly reviewed by the executive leadership team and the Board. The company has well-established relationships with service providers regionally, domestically and globally. Cooper Energy collaborates with industry colleagues to partner in offshore campaigns, for example, as a means to share access to skills and experience. This includes the engagement of international providers with access to a global workforce. The company also has access to well-known and highly skilled contract personnel engaged to meet the various project requirements. ¹Cooper Energy has been certified by Climate Active as a carbon neutral organisation for its Scope-1, Scope-2 and relevant Scope-3 emissions (embedded energy and business travel). See 2023 Sustainability Report for further information. 58 COOPER ENERGY ANNUAL REPORT 2023Operating and Financial Review For the year ended 30 June 2023 Reconciliations for net loss to nnderlying net loss and underlying EBITDAX Reconciliation to underlying EBITDAX¹ Underlying loss Add back: Tax impact of underlying adjustments Net finance costs Accretion expense Tax benefit Depreciation Amortisation Exploration and evaluation expense A$ million A$ million A$ million A$ million A$ million A$ million A$ million A$ million Underlying EBITDAX A$ million Reconciliation to underlying loss² Net loss after income tax A$ million Adjusted for: OGPP reconfiguration and commissioning works OGPP acquisition costs OGPP integration costs Doubtful debts APA toll normalisation Leadership restructuring costs Restoration expense/(income) NOGA levy Impairment Tax impact of underlying adjustments Underlying loss A$ million A$ million A$ million A$ million A$ million A$ million A$ million A$ million A$ million A$ million A$ million FY23 (5.6) 25.8 8.5 18.0 (36.2) 38.7 60.1 - 109.3 FY23 (68.5) 0.4 1.5 4.3 2.8 2.9 2.7 46.3 1.7 26.1 (25.8) (5.6) FY22 14.4 10.7 9.1 4.5 (12.2) 3.4 50.6 0.2 80.7 FY22 (10.6) Change (20.0) % (138.9%) 15.1 141.1% (0.6) 13.5 (24.0) 35.3 9.5 (0.2) 28.6 (6.6)% 300.0% (196.7%) N/M 18.8% N/M 35.4% Change (57.9) % N/M 15.1 (14.7) (97.4%) - - - - - 19.0 1.6 - (10.7) 1.5 4.3 2.8 2.9 2.7 27.3 0.1 26.1 N/M N/M N/M N/M N/M 143.7% 6.2% N/M (15.1) 141.1% 14.4 (20.0) N/M ¹ Earnings before interest, tax, depreciation, amortisation, restoration, exploration and evaluation expense and impairment. ² No adjustment has been made for the temporary loss in revenue at PEL 92 associated with the change in the crude marketing arrangements (previously oil was sold at the inlet to the South Australia Cooper Basin joint venture facilities at Moomba whereas, from 1 July 2022, revenue is recognised upon sale ex-Port Bonython). 59 COOPER ENERGY ANNUAL REPORT 2023 Directors’ Statutory Report For the year ended 30 June 2023 The Directors present their report together with the Consolidated Financial Report of the Group, being Cooper Energy Limited (the “parent entity” or “Cooper Energy” or “Company”) and its controlled entities, for the financial year ended 30 June 2023, and the Independent Auditor’s Report thereon. 1. Directors The Directors of the parent entity at any time during or since the end of the financial year are: Mr John C. CONDE AO B.Sc. B.E(Hons), MBA CHAIRMAN INDEPENDENT NON- EXECUTIVE DIRECTOR Appointed 25 February 2013 Experience and expertise Mr Conde has extensive experience in business and commerce and in chairing high profile business, arts and sporting organisations. Previous positions include non-executive director of BHP Billiton (ASX:BHP), Chairman of Bupa Australia, Chairman of Pacific Power (the Electricity Commission of NSW), Chairman of the Sydney Symphony Orchestra, director of AFC Asian Cup, Chairman of Events NSW, President of the National Heart Foundation and Chairman of the Pymble Ladies’ College Council. Current and other directorships in the last 3 years Mr Conde is Chairman of The McGrath Foundation (since 2013 and director since 2012). He is also President of the Commonwealth Remuneration Tribunal (since 2003) and Chairman of Dexus Wholesale Property Fund (DWPF) (since 2020). Mr Conde is former Deputy Chairman of Whitehaven Coal Limited (ASX:WHC) (2007-2022) and former director of Dexus Property Group (ASX:DXS) (2009 – 2020). Special responsibilities Mr Conde is Chairman of the Board of Directors. Effective 19 August 2021 he is also a member of the People & Remuneration Committee and is the Chairman of the Governance & Nomination Committee. Ms Jane L. NORMAN B.Sc.,B.Eng.(Hons) PGDip GAICD MANAGING DIRECTOR AND CEO Appointed 20 March 2023 Experience and expertise Jane has worked and studied in Australia and the UK and brings 30 years of industry experience in the energy markets. She began her career with Shell International Exploration & Production as a Process Engineer in operations and then as a Commercial Advisor in The Hague, Aberdeen and London. Subsequently, in London, Jane held corporate finance and equity capital markets roles with Cazenove & Co (now JP Morgan Cazenove) and Goldman Sachs. Jane returned to Australia to join Santos where she held senior commercial, corporate strategy and Executive Committee roles. She led major strategic initiatives at Santos and played a key role in Santos’ growth strategy, in particular the merger with Oil Search. During her time at Santos Jane helped drive the transformation of company performance - helping to establish the growth strategy focused on cash generation and shareholder returns and, more recently, the company’s energy transition strategy. Jane holds a Bachelor of Science (Pure Mathematics and Chemistry) and Bachelor of Chemical Engineering (Hons) from the University of Sydney and a Graduate Diploma in Management and Economics of Natural Gas (Distinction) from the University of Oxford. Jane is a Graduate of the Australian Institute of Company Directors. Current and other directorships in the last 3 years Ms Norman is a director of the wholly owned subsidiaries of Cooper Energy Limited and is on the Board of the Australian Petroleum Production and Exploration Association (since 2023). Special responsibilities Ms Norman is Managing Director and CEO. She is responsible for the day-to-day leadership of Cooper Energy, and is the leader of the Executive Leadership Team. 60 COOPER ENERGY ANNUAL REPORT 2023Directors’ Statutory Report For the year ended 30 June 2023 Mr Timothy G. BEDNALL LLB (Hons) INDEPENDENT NON- EXECUTIVE DIRECTOR Appointed 31 March 2020 Experience and expertise Mr Bednall is a highly experienced and respected corporate lawyer and law firm manager. He is a partner of King & Wood Mallesons (KWM), where he specialises in mergers and acquisitions, capital markets and corporate governance, representing public company and government clients. Mr Bednall has advised clients in the oil and gas and energy sectors throughout his career. Ms Victoria J. BINNS B. Eng (Mining – Hons 1), Grad Dip SIA, FAusIMM, GAICD INDEPENDENT NON- EXECUTIVE DIRECTOR Appointed 2 March 2020 Mr Bednall was the Chairman of the Australian partnership of KWM from January 2010 to December 2012, during which time the merger of King & Wood and Mallesons Stephen Jaques was negotiated and implemented. He was also Managing Partner of M&A and Tax for KWM Australia from 2013 to 2014, and Managing Partner of KWM Europe and Middle East from 2016 to 2017. He was General Counsel of Southcorp Limited (which became the core of Treasury Wine Estates Limited) from 2000 to 2001. Current and other directorships in the last 3 years Mr Bednall is a board member of the National Portrait Gallery Foundation (since 2018) and a director of Pooling Limited (since 2017). Special responsibilities Effective 19 August 2021 Mr Bednall is a member of the Audit Committee, the People & Remuneration Committee and the Governance & Nomination Committee. Experience and expertise Ms Binns has over 35 years’ experience in the global resources and financial services sectors including more than 10 years in executive leadership roles at BHP and 15 years in financial services with Merrill Lynch Australia and Macquarie Equities. During her career at BHP, Ms Binns’ roles included Vice President Minerals Marketing, leadership positions in the metals and coal marketing business, Vice President of Market Analysis and Economics and was a member of the first BHP Global Inclusion and Diversity Council. Prior to joining BHP, Ms Binns held a number of board and senior management roles at Merrill Lynch Australia including Managing Director and Head of Australian Research, Head of Global Mining, Metals and Steel, and Head of Australian Mining Research. She was also co-founder and Chair of Women in Mining and Resources Singapore. Current and other directorships in the last 3 years Ms Binns is currently a non-executive director of Evolution Mining (ASX:EVN) (since 2020) and Sims Limited (ASX:SGM) (since 2021). She is also a non-executive director of the Carbon Market Institute and a member of the J.P. Morgan Australia & NZ Advisory Council. Special responsibilities Effective 19 August 2021 Ms Binns is the Chairman of the Audit Committee and is a member of the Risk & Sustainability Committee. 61 COOPER ENERGY ANNUAL REPORT 2023Directors’ Statutory Report For the year ended 30 June 2023 Ms Giselle M. COLLINS B. Ec, CA GAICD INDEPENDENT NON- EXECUTIVE DIRECTOR Appointed 19 August 2021 Ms Elizabeth A. DONAGHEY B.Sc., M.Sc. INDEPENDENT NON- EXECUTIVE DIRECTOR Appointed 25 June 2018 Mr Jeffrey W. SCHNEIDER B.Com INDEPENDENT NON- EXECUTIVE DIRECTOR Appointed 12 October 2011 Experience and expertise Ms Collins has broad executive and director experience across finance, treasury and property disciplines. Ms Collins is also active with not-for-profit organisations and has a strong interest in sustainability across many of her involvements. Ms Collins’ executive positions included General Manager Property, Treasury and Tourism of NRMA, Chief Executive Officer, Property and General Manager Finance with the Hannan Group, and Senior Manager, Audit Services with KPMG Switzerland. Current and other directorships in the last 3 years Ms Collins is currently Chairman of AMP Limited’s listed managed investment schemes (since 2020), a trustee director of the Royal Botanic Gardens and Domain Trust (since 2019), non-executive director of Generation Development Group (since 2018), Chairman of Hotel Property Investments Limited (ASX:HPI) (Chairman since July 2022 and director since 2017) and Chairman for Indigenous Business Australia in The Darwin Hotel Pty Limited (since 2014). Ms Collins is a former non-executive director and Chairman of the following companies: Aon Superannuation (2016-2017), The Travelodge Hotel Group (2009- 2013), The Heart Research Institute Limited (2003-2011) as well as a non-executive director of Generation Life (2018 – 2021) and Peak Rare Earths Limited (ASX:PEK) (2021 – 2023). Special responsibilities Effective 19 August 2021 Ms Collins is a member of the Audit Committee and the Risk & Sustainability Committee Experience and expertise Ms Donaghey brings over 30 years’ experience in the energy sector including technical, commercial and executive roles in EnergyAustralia, Woodside Energy and BHP Petroleum. Ms Donaghey’s experience includes non-executive director roles at Imdex Ltd (an ASX-listed provider of drilling fluids and downhole instrumentation), St Barbara Ltd (a gold explorer and producer), and the Australian Renewable Energy Agency. She has performed extensive committee roles in these appointments, serving on audit and compliance, risk and audit, technical and regulatory, remuneration and health and safety committees. Current and other directorships in the last 3 years Ms Donaghey is currently a non-executive director of the Australian Energy Market Operator (AEMO) (since 2017) and a non-executive director of Ampol Limited (ASX: ALD) (since 2021). Special responsibilities Effective 19 August 2021 Ms Donaghey is a member of the Risk & Sustainability Committee, the People & Remuneration Committee and the Governance & Nomination Committee. Effective 23 June 2023 Ms Donaghey is the Chairman of the Risk & Sustainability Committee. Experience and expertise Mr Schneider has over 30 years of experience in senior management roles in the oil and gas industry, including 24 years with Woodside Energy. He has extensive corporate governance and board experience as both a non-executive director and chairman in resources companies. Current and other directorships in the last 3 years Mr Schneider does not currently hold any other directorships. Special responsibilities Effective 19 August 2021 Mr Schneider is Chairman of the People & Remuneration Committee and a member of the Governance & Nomination Committee. 62 COOPER ENERGY ANNUAL REPORT 2023Directors’ Statutory Report For the year ended 30 June 2023 Mr David P. MAXWELL M.Tech, FAICD MANAGING DIRECTOR Appointed 12 October 2011 Retired 20 March 2023 Mr Hector M. GORDON B.Sc. (Hons). INDEPENDENT NON- EXECUTIVE DIRECTOR 26 June 2012 – 23 June 2017 NON-EXECUTIVE DIRECTOR Appointed 24 June 2017 Retired 23 June 2023 Experience and expertise Mr Maxwell is a leading oil and gas industry executive with more than 25 years in senior executive roles with companies such as BG Group, Woodside Energy and Santos. Mr Maxwell led many large commercial, marketing and business development projects. Prior to joining Cooper Energy Mr Maxwell worked with the BG Group, where he was responsible for all commercial, exploration, business development, strategy and marketing activities in Australia and led BG Group’s entry into Australia and Asia including a number of material acquisitions. Mr Maxwell has served on a number of industry association boards, government advisory groups and public company boards. Current and other directorships in the last 3 years Mr Maxwell was on the board of the Australian Petroleum Production & Exploration Association (2018-2023). Until Mr Maxwell’s retirement from Cooper Energy he was a director of the Company’s wholly owned subsidiary companies. Special responsibilities Prior to his retirement, Mr Maxwell was Managing Director. He was responsible for the day-to-day leadership of Cooper Energy and was the leader of the Executive Leadership Team. Experience and expertise Mr Gordon is a geologist with over 40 years’ experience in the upstream petroleum industry, primarily in Australia and Southeast Asia. He joined Cooper Energy in 2012, initially as Executive Director – Exploration & Production and subsequently moved to his position as non-executive director in 2017. Mr Gordon was previously Managing Director of Somerton Energy until it was acquired by Cooper Energy in 2012. Previously he was an Executive Director with Beach Energy Limited, where he was employed for more than 16 years. In this time Beach Energy experienced significant growth and Mr Gordon held a number of roles including Exploration Manager, Chief Operating Officer and, ultimately, Chief Executive Officer. Current and other directorships in the last 3 years Mr Gordon is a Non-Executive Director of Bass Oil Limited ASX: BAS (since 2014). Special responsibilities Prior to his retirement, Mr Gordon was the Chairman of the Risk & Sustainability Committee and a member of the Audit Committee. 2. Company secretary Ms Nicole Ortigosa B.A., LLB (Hons), Grad Dip Legal Practice was appointed to the position of Acting Company Secretary and General Counsel effective from 21 April 2023 and was appointed to the permanent position of Company Secretary and General Counsel effective 17 July 2023. Nicole has almost 15 years’ experience as a corporate and commercial lawyer, specialising in the energy and resources sector. Prior to joining Cooper Energy she worked for top tier law firms across Australia, including Clifford Chance and Minter Ellison. Nicole’s experience covers all legal, corporate, and commercial aspects of the business, including joint ventures, gas sales, infrastructure, environment, regulatory, procurement, mergers and acquisitions, corporate governance and compliance. Nicole started at Cooper Energy in 2017 and prior to becoming General Counsel & Company Secretary was the Legal Manager. Amongst other matters, she has advised the company on the development of the Sole gas field, the acquisition of AGP and associated infrastructure and the acquisition of OGPP and associated onshore and offshore pipeline infrastructure. She holds a Bachelor of Laws with Honours from the University of Adelaide and a Graduate Diploma in Legal Practice from the Law Society of South Australia 63 COOPER ENERGY ANNUAL REPORT 2023Directors’ Statutory Report For the year ended 30 June 2023 3. Directors’ meetings The number of Directors’ meetings (including meetings of committees of Directors) and number of meetings attended by each of the Directors during the financial year were: Director Board Meetings Audit Committee Meetings Risk & Sustainability Committee Meetings People & Remuneration Committee Meetings Governance & Nomination Committee Meetings Mr J. Conde Mr J. Norman¹ Mr T. Bednall Ms V. Binns Ms E. Donaghey Mr J. Schneider Ms G. Collins Mr D. Maxwell² Mr H. Gordon³ A 9 2 9 9 9 9 9 7 9 B 9 2 9 9 9 9 9 7 9 A - - 4 4 - - 4 - 4 B - - 4 4 - - 4 - 4 A - - - 4 3 - 4 - 4 B - - - 4 4 - 4 - 4 A 4 - 4 - 3 4 - - - B 4 - 4 - 4 4 - - - A 1 - 1 - 1 1 - - - B 1 - 1 - 1 1 - - - A = Number of meetings attended. B = Number of meetings held during the time the Director held office, or was a member of the Committee, during the year. ¹Ms Norman was appointed as Managing Director and CEO on 20 March 2023 ²Mr Maxwell retired effective from 20 March 2023 ³Mr Gordon retired effective from 23 June 2023 4. Remuneration Report (audited) Information about the remuneration of the Company’s key management personnel for the financial year ended 30 June 2023 is set out in the Remuneration Report. The Remuneration Report forms part of the Directors’ Report. It has been prepared in accordance with section 300A of the Corporations Act 2001 and has been audited as required by that Act. Introduction from the Chairman of the People & Remuneration Committee Dear Shareholder, The 2023 financial year (FY23) has seen significant change for the Company, including the retirement of David Maxwell as Managing Director and the appointment of Jane Norman as Managing Director and Chief Executive Officer effective 20 March 2023. We also welcomed the Orbost Gas Processing Plant (OGPP) team to Cooper Energy following the Major Hazard Facilities License (MHFL) transfer, effective 22 May 2023. The Company’s performance in the 2023 financial year was below the target levels we had set at the start of the year. This is reflected in our Corporate Scorecard results. Shareholders, the Board and all staff are acutely aware that the Company’s underperformance against our targets has in turn been reflected in weak share price outcomes. Everyone in the Company is focused on ensuring material improvement in both business performance and share price outcomes in the year ahead. This Remuneration Report reflects achievement levels in the 2023 financial year and the associated remuneration outcomes for the key management personnel (KMP). The report documents the Company’s remuneration framework and guiding principles and illustrates clearly the impact of the Company’s performance on the remuneration outcomes. We will seek shareholders’ support for the Remuneration Report at the 2023 Annual General Meeting. The People & Remuneration Committee believes that the FY23 remuneration outcomes are appropriate, taking into account the Company’s performance, changes in the business and the employment market generally. Remuneration Report context: 2023 financial year The Company’s performance in the 12 months to 30 June 2023 is reported in the Operating and Financial Review of the Financial Report. This performance and how it compared with the specific targets of the Corporate Scorecard provide the context of the Remuneration Report. In the 2023 financial year, the Company has been successful in maintaining its strong performance in Health and Safety to industry leading levels together with no recordable environmental incidents. Whilst these results were very pleasing, other scorecard dimensions namely, Production and Financials, Projects and Asset Management, Growth and Portfolio Management, and People, Culture and Enablers failed to either achieve or to exceed target levels. As a result, the Board determined that there will be no short-term incentive plan (STIP) payment for FY23 as it relates to Company performance. This decision is not intended to diminish the considerable efforts of the Cooper Energy team, who remain committed to delivering our key business imperatives in order to bring future 64 COOPER ENERGY ANNUAL REPORT 2023Directors’ Statutory Report For the year ended 30 June 2023 October 2023. The next general review of base salaries will be 1 October 2024. Short term incentive plan (STIP): The Board determined that there will be no STIP payment for FY23 as it relates to Company performance, as overall targets set within the corporate scorecard were not satisfied to a level that payment was justified. The Board determined that STIP relating to individual performance would be awarded to KMP and staff generally based on achievement against individual objectives. The FY23 STIP outcomes for the KMP are included in this report in 4.6.3. Long term incentive plan (LTIP): Our remuneration framework is also designed to reward superior performance over the long term and align executive key management personnel performance with shareholder value. The performance of the share price over the past 3 years has been a concern for all shareholders including the Board and management. Consistent with this performance, there was no LTIP vesting in December 2021 (FY22) or December 2022 (FY23). As stated above, ensuring strong business performance which is in turn reflected in improved share price performance remains a key area of focus. LTIP performance outcome is captured in 4.6.4. Directors fees: During FY23 there were no increases to non-executive director remuneration. The recent increase in statutory superannuation payments has not resulted in an increase in fees paid to individual directors. The most recent increase to non-executive director fee remuneration occurred on 1 July 2019. The Board has no current plan to increase Directors Fees. Despite disappointing business outcomes, the level of energy and commitment to succeed in the Company is very strong at all locations and levels. The Board is very appreciative of the efforts of all staff in this regard. We thank also David Maxwell who as the former Managing Director recommended the strategy which created the platform. Under Jane Norman’s leadership we are confident we will realise the company’s potential. Yours sincerely Mr Jeffrey Schneider Chairman of the People & Remuneration Committee success. The Board determined that STIP relating to individual performance will be awarded to KMP and Staff based on achievement against individual objectives. The FY23 STIP outcomes for the KMP are included in this report. Remuneration developments The new Managing Director and Chief Executive Officer, Jane Norman, has implemented a number of changes to the organisational structure of Cooper Energy. This is intended to sharpen business accountabilities and includes a reduction in the number of executive key management personnel (KMP). The KMP are those personnel that have the authority and responsibility for planning, directing and controlling the activities of the entity, directly or indirectly including any director (whether executive or otherwise) of the entity. For completeness, this report provides KMP remuneration for those included as KMP during FY23. Next year’s Remuneration Report will report on the revised KMP executive team being the Managing Director and Chief Executive Officer, Chief Financial Officer, Chief Operating Officer (a newly created position with an appointment to be announced in the first half of FY24), Chief Commercial Officer, and Chief Exploration and Subsurface Officer. Other executive roles shown in this report continue to be part of the Cooper Energy management team. The revised KMP group better reflects those directly responsible for planning, directing and controlling the activities of Cooper Energy and the size of the business. The revised number of executive KMP better aligns with our industry peers. Remuneration paid to the previous Managing Director, David Maxwell, upon his retirement is also set out in this report. The payments made to him were consistent with the practice adopted for other senior staff retirements. The Company’s remuneration framework will be reviewed during FY24 to ensure it is meeting its intended objectives of providing incentives to deliver superior performance to our shareholders, alongside attracting and retaining high calibre employees. The review is intended to strengthen the connection between the shareholder experience and remuneration outcomes. Remuneration outcomes Fixed Annual Remuneration: Increases to the statutory superannuation contribution effective 1 July 2023 have been applied to all employees including the Managing Director and Chief Executive Officer. Those executive KMP who had been with the Company for the full financial year (FY23) were included in a salary review with the total increase being 3.55% (including the statutory change to superannuation). Adjustments to salary considered any additional responsibility and benchmarking data within the resources industry (incorporating the hydrocarbon sector). Increases to base salaries are seen as comparable to our relevant peer companies and industry generally and are effective 1 65 COOPER ENERGY ANNUAL REPORT 2023Directors’ Statutory Report For the year ended 30 June 2023 Contents Page 4.1 Introduction .................................................66 Name Position Period as KMP Key management personnel 4.2 Key Management Personnel covered in this Report ..............................................66 4.3 Remuneration Governance ........................67 4.4 Nature & Structure of Executive KMP Remuneration ....................................67 4.5 Cooper Energy’s Five-Year Performance and Link to Remuneration ...........................73 4.6 2023 Executive KMP Performance and Remuneration Outcomes ............................74 Non-Executive Directors Mr J. Conde AO Chairman Full Year Mr T. Bednall Non-Executive Director Full Year Ms V. Binns Non-Executive Director Full Year Ms G. Collins Non-Executive Director Full Year Ms E. Donaghey Non-Executive Director Full Year Mr J. Schneider Non-Executive Director Full Year Former Non Executive KMP 4.7 Executive KMP Employment Contracts ......79 Mr H. Gordon Executive KMP Ms J. Norman Former Non-Executive Director Part Year¹ Managing Director & Chief Executive Officer Part Year² Mr. D. Young Chief Financial Officer Full Year Mr E. Glavas General Manager Commercial & Development Mr I. MacDougall General Manager HSE, Technical Services and IT Full Year Full Year Mr A. Thomas Mr A. Haren Former Executive KMP Mr D. Maxwell Mr M. Jacobsen Ms A. Jalleh General Manager Exploration & Subsurface and Projects Full Year General Manager People & Remuneration Full Year Former Managing Director Former General Manager Projects & Operations Former Company Secretary and General Counsel Part Year³ Part Year4 Part Year5 1 Mr Gordon retired effective 23 June 2023. ² Ms Norman commenced effective 20 March 2023. ³ Mr Maxwell stood down from the role of Managing Director effective from 20 March 2023. Mr Maxwell retired from Cooper Energy effective 3 July 2023. 4 Mr Jacobsen stood down from the role of General Manager Project & Operations effective from 24 April 2023. 5 Ms Jalleh resigned effective 19 May 2023. 4.8 2023 Remuneration Outcomes for Executive KMP ............................................80 4.9 Nature of Non-Executive Director Remuneration .............................................84 4.1 Introduction This Remuneration Report (Report) details the approach to remuneration frameworks, outcomes and performance for Cooper Energy. The Remuneration Report forms part of the Directors’ Report and provides shareholders with an understanding of the remuneration principles and practices in place for Key Management Personnel (KMP) for the reporting period. 4.2 Key Management Personnel covered in this report In this Report, KMP are the people who have the authority and responsibility for planning, directing and controlling the activities of the Group, either directly or indirectly. They are: • • • the Non-Executive Directors; the Managing Director and Chief Executive Officer; and selected executives on the Executive Leadership Team. The Managing Director and Chief Executive Officer and selected executives on the Executive Leadership Team are referred to in this Report as “Executive KMP”. The following table sets out the KMP of the Group during the reporting period and the period they were KMP: 66 COOPER ENERGY ANNUAL REPORT 2023 Directors’ Statutory Report For the year ended 30 June 2023 This report sets out KMP remuneration for those included as KMP during FY23. Next year’s Remuneration Report will report solely on the revised KMP team being the Managing Director and Chief Executive Officer (Jane Norman), Chief Financial Officer (Dan Young), Chief Operating Officer (a newly created position with an appointment to be announced in the first half of FY24), Chief Commercial Officer (Eddy Glavas), and Chief Exploration and Subsurface Officer (Andrew Thomas). All Non-Executive Director roles continue to be captured in the KMP group. The revised KMP group better reflects those directly responsible for planning, directing and controlling the activities of Cooper Energy and the size of the business. The revised number of executive KMP better aligns with our industry peers. Other executive roles shown in this report continue to be part of the Cooper Energy management team. 4.3 Remuneration governance 4.3.1 Philosophy and objectives The Company is committed to a remuneration philosophy that aligns with its business strategy and encourages superior performance and shareholder returns. Cooper Energy’s approach towards remuneration is aimed at ensuring that an appropriate balance is achieved between: • maximising sustainable growth in shareholder returns; • operational and strategic requirements; and • providing attractive and appropriate remuneration packages. The primary objectives of the Company’s remuneration policy are to: • attract and retain high calibre employees; • ensure that remuneration is fair and competitive with both peers and competitor employers; • provide significant incentive to deliver superior performance (when compared to peers) against Cooper Energy’s strategy and key business goals without rewarding conduct that is contrary to the Cooper Energy values or risk appetite; • achieve the most effective returns (employee productivity) for total employee spend; and • ensure remuneration transparency and credibility for all employees and in particular for Executive KMP. Cooper Energy’s policy is to pay Fixed Annual Remuneration (FAR) at the median level compared to resource industry benchmark data and supplement this with “at risk” remuneration to bring total remuneration within the upper quartile when outstanding performance is achieved. The Company’s remuneration framework will be reviewed during FY24 to ensure it is meeting its intended objectives in providing incentives to attract, retain and incentivise high calibre employees while at the same time is aligned with shareholder experience. The review is intended to strengthen the connection between the shareholder experience and remuneration outcomes. 4.3.2 People & Remuneration Committee The People & Remuneration Committee (which, as at the date of this report, is comprised of 4 Non-Executive Directors, all of whom are independent) makes recommendations to the Board about remuneration strategies and policies for the Executive KMP and considers matters related to organisational structure and operating model, company culture and values, diversity, succession for senior executives, and executive development and talent management. The ultimate responsibility for, and power to make company decisions with respect to these matters, remains with the full Board. On an annual basis, the People & Remuneration Committee makes recommendations to the Board about the form of payment and incentives to Executive KMP and the amount. This is done with reference to Company performance and individual performance of the Executive KMP, relevant employment market conditions, current industry practices and independent remuneration benchmark reports. 4.3.3 External remuneration advisers The People & Remuneration Committee may consider advice from external advisors who are engaged by and report directly to the Committee. Such advice will typically cover Non-Executive Director fees, Executive KMP remuneration and advice in relation to equity plans. The Corporations Act 2001 requires companies to disclose specific details regarding the use of remuneration consultants. The mandatory disclosure requirements only apply to those advisors who provide a “remuneration recommendation” as defined in the Corporations Act 2001. The Committee did not receive any remuneration recommendations during the FY23 reporting period. 4.4 Nature & structure of Executive KMP remuneration Executive KMP remuneration during the reporting period consisted of a mix of: • Fixed Annual Remuneration (FAR); • STIP participation; • benefits such as, internet allowance and car parking; and • LTIP (composed of performance rights (PRs) and share appreciation rights (SARs) under the Company’s amended Equity Incentive Plan approved by shareholders at the 2022 AGM (EIP)). In the case of the former Managing Director remuneration included an allowance for accommodation. It is the Company’s policy that the performance-based (or at-risk) pay forms a significant portion of the Executive KMPs’ total remuneration. The Company aims to achieve an appropriate balance between rewarding operational performance (through the STIP reward) and rewarding long-term sustainable performance (through the LTIP). 67 COOPER ENERGY ANNUAL REPORT 2023Directors’ Statutory Report For the year ended 30 June 2023 4.4 Nature & structure of Executive KMP remuneration (continued) 4.4.1 Remuneration strategy and framework - linking reward to performance The Company’s current remuneration profile for Executive KMP (at Maximum Performance Super Stretch) is as follows: The remuneration strategy sets the remuneration framework and drives the design and application of remuneration for the Company, including Executive KMP. Managing Director & CEO* Other Executive KMP 30.8% FAR 30.8% LTIP 38.5% STIP 22.7% STIP 31.8% LTIP 45.5% FAR *The above split of fixed and at risk pay reflects the ongoing remuneration for the Managing Director & CEO. For the first year the Managing Director’s remuneration split will be 28.6% FAR, 35.7% STIP and 35.7% LTIP. A higher LTIP applies to the first-year invitation for the Managing Director & CEO (Jane Norman) due to the timing of this appointment. This was disclosed in our ASX announcement of 19 December 2022. The remuneration strategy: • encourages a strong focus on financial and operational performance, and motivates Executive KMP to deliver sustainable business results and returns to the Company’s shareholders over the short and long term; • attracts, motivates and retains appropriately qualified and experienced talent; and • aligns executive and shareholder interests through equity linked plans. The Board believes that remuneration should include a fixed component and at-risk or performance-related components, including both short term and long-term incentives. This remuneration framework is shown in the table following, including how performance outcomes will impact remuneration outcomes for Executive KMP. The Board will continue to review the remuneration framework to ensure it continues to align with the Company’s strategic objectives. No changes to the key elements of the remuneration framework were made in FY23. 4.4.2 Remuneration strategy and framework – Overview – FY23 Performance conditions Remuneration strategy/performance link FIXED ANNUAL REMUNERATION (FAR) Salary and other benefits (including statutory superannuation) Key considerations • • • • Scope of individual’s role Individual’s level of knowledge, skills and expertise Individual performance Market benchmarking FAR is set to attract, retain and motivate the right talent to deliver the strategy and deliver the Company’s financial and operational targets. For executives new to their role, the aim is to set FAR at relatively modest levels, compared to their peers, and to progressively increase as they gain experience and perform at higher levels. This links fixed remuneration to individual performance. 68 COOPER ENERGY ANNUAL REPORT 2023Directors’ Statutory Report For the year ended 30 June 2023 Performance conditions Remuneration strategy/performance link SHORT TERM INCENTIVE PLAN (STIP) Annual incentive opportunity delivered in cash based on Company and Individual performance HSEC and Sustainability KPIs • • Safety incident and environment prevention Sustainability targets Production and Financial KPIs • • • • Production u-EBITDAX Unit opex Net G&A Project and Asset Management KPIs • • Major projects delivery Asset management Growth and Portfolio Management KPIs • • • • Reserves and resources Development project delivery New gas contracts Acquisitions and divestments People, Culture and Enablers KPIs • • • • Staff engagement and enablement Funding Systems and processes, including IT Stakeholder relations STIP performance conditions are designed to support the financial, operational and strategic direction of the Company and are clearly defined and measurable. The achievement of these conditions links to shareholder returns. A large proportion of outcomes are subject to the operational and financial targets of the Company or business unit, depending on the role of the executive, to ensure line of sight. Strategy and project targets ensure that continued focus on future opportunities is maintained. Non-financial targets are aligned to core values (including safety and sustainability) and key strategic and growth objectives. Threshold, Target, Stretch and Super Stretch targets for each measure are set by the Board to ensure that a challenging performance-based incentive is provided. The Board has discretion to adjust STIP outcomes up or down to ensure appropriate individual outcomes and results align with the shareholder experience and Cooper Energy values. LONG TERM INCENTIVE PLAN (LTIP) Three-year incentive opportunity delivered through Performance Rights and Share Appreciation Rights Individual performance KPIs • • Managing Director & CEO (25% weighting) Executive KMP (30% weighting) Individual performance measures are agreed each year. The measures include key business objectives, while also being role-specific, i.e., related to individual and team specific responsibilities Allocation of PRs and SARs encourages executives to ‘behave like shareholders’ from the grant date. The PRs and SARs are restricted and subject to risk of forfeiture at the end of the three-year performance period. The Company believes that encouraging its employees to becomes shareholders is the best way of aligning employee interests with those of the Company’s shareholders. The LTIP also acts as a retention incentive for key talent (due to the three-year vesting peri-od). RTSR is designed to encourage executives to focus on the key performance drivers which underpin sustainable growth in share-holder value. The RTSR performance condition is designed to ensure vesting can only occur where shareholders have enjoyed superior share price performance compared to the peer group shareholders. SARs only have value when there is an increase in the Company’s share price. In general, the Company’s vesting hurdles are intended to be tough-er than our industry peers. LTIP consists of 50% of PRs and 50% SARs. Maximum LTIP grant is 100% of FAR for Managing Director & CEO and 70% of FAR for other Executive KMP. Note: The first LTIP invitation for the new Managing Director & CEO is 125% of FAR due to the timing of their appointment. This was disclosed in our ASX announcement dated 19 December 2022. Relative Total Shareholder Return (RTSR) is the only performance condition. RTSR ensures that LTIP can only vest when the Company’s share price performance is at least at the 50th percentile of the peer group. Maximum LTIP vesting can only occur at or above 90th percentile of the peer group. • • • RTSR performance requires a sustained superior share price performance of the Company compared to a peer group of companies. The peer group companies are 12 ASX- listed companies in the oil and gas sector, with a range of market capitalisation. SARs by their nature have an absolute total shareholder return requirement. No SAR will vest unless the share price appreciates over the measurement period. TOTAL REMUNERATION: The combination of these elements is designed to attract, retain and motivate appropriately qualified and experienced individuals, encourage a strong focus on performance, support the delivery of outstanding returns to shareholders and align executive and stakeholder interests through share ownership. 69 COOPER ENERGY ANNUAL REPORT 2023Directors’ Statutory Report For the year ended 30 June 2023 4.4.3 Fixed annual remuneration (FAR) FAR includes base salary (paid in cash) and statutory superannuation. Executives are paid FAR which is competitive in the markets in which the Company operates and is consistent with the responsibilities, accountabilities and complexities of the respective roles. The Company benchmarks FAR for its Executive KMP against resource industry market surveys (and, in particular, oil and gas companies) which are published annually. Additionally, the pay levels of Executive KMP positions in the Company may be benchmarked against national market executive remuneration surveys. It is the Company’s policy to position itself at the median level of the market when benchmarking FAR. 4.4.4 Short term tncentive plan (STIP) - Overview The STIP is an annual incentive opportunity delivered in cash based on a mix of Company and individual performance. The individual measures are a mixture of business unit and employee-specific goals. The key features of the STIP for FY23 were as follows: FY23 STIP plan Features Details What is the purpose of the STIP? Motivate and reward individuals for their contribution to the annual performance of the Company. How does the STIP align with the interests of Cooper Energy’s shareholders? The STIP is aligned to shareholder interests by encouraging individuals to achieve operational and business milestones in a balanced and sustainable manner whilst growing asset and total company value. What is the vehicle of the STIP award? The STIP award is delivered in the form of a cash payment, usually in October. What is the maximum award opportunity (% of Fixed Remuneration)? Managing Director & CEO 125% Former Managing Director 100% Other Executive KMP 50% What is the performance period? Each year, the Board reviews and approves the performance criteria for the year ahead by approving a Company scorecard and individual performance contracts which are agreed with each Executive KMP. The Company’s STIP operates over a 12-month performance period from 1 July to 30 June. How are the performance measures determined and what are their relative weightings? The measurement of Company performance is based on the achievement of KPIs set out in a Company scorecard. See section 4.6.2 for the Company scorecard measures used for FY23. The KPIs focus on the core elements the Board believes are needed to successfully deliver the Company strategy and maximise sustainable shareholder returns. For each KPI in the scorecard, a base or threshold performance level is established as well as a Target, Stretch and Super Stretch (i.e., maximum). Personal performance measures are agreed between each Executive KMP and Cooper Energy each year. The relative weighting of Company scorecard and individual performance is as follows: Managing Director & CEO: 75% Company: 25% individual Other Executive KMP: 70% Company: 30% individual Performance measures are challenging, and maximum award opportunities are only achieved by outstanding performance. 50% of the maximum award opportunity will be awarded if the Company meets target level performance. Target level KPIs are set at a challenging and achievable level of performance (and not at the base level of performance). 0% STIP will be awarded for base level achievement. 0% STIP will be awarded if during any measurement period the Company sustains a fatality or major environmental incident. Irrespective of the scorecard outcome, payment of any STIP is entirely at the discretion of the Board. 70 COOPER ENERGY ANNUAL REPORT 2023Directors’ Statutory Report For the year ended 30 June 2023 4.4.5 Long term incentive plan (LTIP) - Overview In the reporting period, the LTIP involved grants of PRs and SARs under the EIP. The key features of the grants made in the 2023 financial year (granted December 2022) are set out in the following table: FY23 LTIP plan Features Details What is the purpose of the LTIP? The Company believes that encouraging its employees, including Executive KMP, to become shareholders is the best way of aligning their interests with those of the Company’s shareholders. Having a LTIP is also intended to be a retention incentive, with a vesting period of at least three years before securities under the plan are available to employees. How is the LTIP aligned to shareholder interests? Employees only benefit from the LTIP when there is sustained superior share price performance of the Company, including when compared to relevant peer group companies. This aligns the LTIP with the interests of shareholders. What is the vehicle of the LTIP? During the reporting period, the LTIP involved grants of 50% PRs and 50% SARs. A PR is a right to acquire one fully paid share in the Company, provided a specified hurdle is met. SARs are rights to acquire shares in the Company to the value of the difference in the Company share price between the grant date and vesting date. What is the maximum an-nual LTIP grant (% of Fixed Remuneration)? Managing Director & CEO: 100% (refer note below) Former Managing Director: 100% Other Executive KMP: 70% What is the LTIP perfor-mance period? What are the performance measures? Note: The first LTIP invitation for the new Managing Director & CEO is 125% of FAR due to the timing of their appointment. This was disclosed in our ASX announcement dated 19 December 2022. The performance period is three years. 100% of the grant (both PRs and SARs) is subject to a relative total shareholder return (“RTSR”) performance measure. RTSR is a common long-term incentive measure across ASX-listed companies and is aligned with shareholder returns. Relative measures ensure that maximum incentives are only achieved if Cooper Energy’s performance exceeds that of its peers and therefore supports competitive returns against other comparable organisations. In addition to the RTSR performance measure set by the Board, SARs by their nature also have a natural absolute total shareholder return measure. No SARs will be exercisable unless the share price appreciates over the measurement period. What is the vesting schedule? The level of vesting will be determined based on the ranking against the peer group of 12 companies, in accordance with the following schedule: • • • • below the 50th percentile, no rights vest; at the 50th percentile, 30% of the rights vest; between the 50th percentile and 90th percentile, pro rata vesting; and at the 90th percentile or above, 100% of the rights will vest. The vesting schedule reflects the Board’s requirement that performance measures are challenging, and maximum award opportunities are only achieved by outstanding performance. 71 COOPER ENERGY ANNUAL REPORT 2023Directors’ Statutory Report For the year ended 30 June 2023 Features Details Which companies make up the Relative Total Shareholder Return peer group? The RTSR of the Company is measured as a percentile ranking compared to the following comparator group of 12 listed entities: Beach Energy Limited, Buru Energy Limited, Carnarvon Petroleum Limited, Central Petroleum Limited, Galilee Energy Limited, Karoon Gas Australia Limited, Norwest Energy (subsequently acquired and delisted), Santos Limited, Strike Energy Limited, Tamboran Resources Limited, Warrego Energy Limited (subsequently acquired and delisted), and Woodside Energy Group. The peer group is based on a group of ASX-listed companies in the oil and gas sector, with a range of market capitalisation. If following the review of the remuneration strategy RTSR continues to be used, the composition of this group will be reviewed in FY24. What happens on cessation of employment? Generally, if an employee ceases employment prior to the vesting date (e.g., to take a position with another company), they will forfeit all awards. In the case of “qualifying leavers” as defined (examples of which include redundancy, retirement or incapacity), awards may be retained unless the Board determines otherwise. The Board also has the discretion to determine that some or all awards may be retained upon cessation of employment. What happens if there is a change of control? In the event of a change of control, unless the Board determines otherwise, pro-rata vesting will occur on the basis of the proportion of the relevant performance period that has elapsed. Who can participate in the LTIP? Will the Company make any changes to the LTIP for the grant to be made in the 2024 financial year? Eligibility is generally restricted to Executive KMP. As indicated earlier in this Remuneration Report, a review of remuneration structure will be undertaken in FY24. This may have the effect of changing the approach used for LTIP. Mr Maxwell and Mr Jacobsen were deemed to be qualifying leavers by the Board and as such has exercised discretion to remove the service condition of the LTIP. 72 COOPER ENERGY ANNUAL REPORT 2023Directors’ Statutory Report For the year ended 30 June 2023 4.5 Cooper Energy’s five-year performance and link to remuneration The following graphs illustrate the Company’s five-year performance, which link to the remuneration strategy and framework: Total recordable injury frequency rate (events per hours worked, where a lower value is better) Sales revenue ($ million) 6.92 3.53 0.00 4.38 0.00 75.5 78.1 131.7 205.4 196.9 FY19 FY20 FY21 FY22 FY23 FY19 FY20 FY21 FY22 FY23 Links directly to Company STIP reward outcome as a HSEC & Sustainability KPI. Links directly to Company STIP reward outcome as a Production & Financial KPI. Annual production (MMboe) Proved & probable reserves (MMboe) 3.31 3.56 2.63 1.31 1.56 52.7 49.9 47.1 39.5 36.3 FY19 FY20 FY21 FY22 FY23 FY19 FY20 FY21 FY22 FY23 Links directly to Company STIP reward outcomes as a Production & Financial KPI. Links directly to Company STIP reward outcome as a Growth & Portfolio Management KPI. Financial – underlying profit after tax ($ million) Financial - underlying EBITDAX ($ million) 13.3 14.4 (6.6) (25.9) (5.6) FY19 FY20 FY21 FY22 FY23 32.9 29.6 30.0 80.7 109.3 FY19 FY20 FY21 FY22 FY23 Links indirectly to Company STIP reward outcomes via Production & Financial KPIs. Links directly to Company STIP reward outcome as a Financial KPI. Financial – total shareholder return (%) Share price – as at 30 June ($ per share) 40.3 (30.6) FY20 FY19 (5.8) (30.7) FY21 FY22 (38.8) FY23 0.54 0.38 0.26 0.25 0.15 FY19 FY20 FY21 FY22 FY23 Links directly to Company LTIP reward outcome by increasing shareholder value. Links directly to Company LTIP reward outcome by increasing shareholder value compared to peers. Market capitalisation - as at 30 June ($ million) 875.6 610.0 424.1 583.1 394.7 In FY23, and in the past five years, dividends were not paid by the Company to its shareholders, nor was there a return of capital to shareholders, consistent with the growth reinvestment objectives of the Company. FY19 FY20 FY21 FY22 FY23 Links directly to Company LTIP reward outcome by increasing shareholder value compared to peers. 73 COOPER ENERGY ANNUAL REPORT 2023Directors’ Statutory Report For the year ended 30 June 2023 4.6 2023 Executive KMP performance and remuneration outcomes 4.6.1 Fixed annual remuneration outcome 4.6.2 STIP performance outcomes – Company results Increases to the statutory superannuation contribution, effective 1 July 2023, have been applied to all employees including the Managing Director and Chief Executive Officer. There has been no increase to the base salary of the Managing Director and Chief Executive Officer. Those executive KMP who had been with the Company for the full financial year (FY23) were included in a salary review with the total increase being 3.55% (including the statutory change to superannuation). Adjustments to salary also considered any additional responsibility and benchmarking data within the resources industry (incorporating the hydrocarbon sector). Increases to base salaries are seen as comparable to our relevant peer companies and industry generally and are effective 1 October 2023. The next general review of base salaries will be 1 October 2024. Performance measure (FY23 weighting%) Performance measure outcome The Board determined that there will be no short-term incentive plan (STIP) payment for FY23 as it relates to Company performance. Whilst the Company has been successful in maintaining its strong performance in Health, Safety and Environment, other scorecard dimensions namely, Production and Financials, Projects and Asset Management, Growth and Portfolio Management, and People, Culture and Enablers failed to achieve or exceed target levels. The Board determined a FY23 scorecard assessment result of 21.4/100 (21.4%). Result Threshold Target Stretch Super stretch HSEC (25%) Result: 16.67/25.00 • LTIs = 0 • TRIFR = 4.38 < industry benchmark (5.68) • No process safety events • No recordable environmental incidents ≥ level 2 • Maintained company and gas product carbon neutral certification • Emissions offset and new projects being reviewed Production & financials (25%) Result: 0/25.00 • FY23 production of 3.5 MMboe; between threshold and target • FY23 u-EBITDAX of $109.3mm; below threshold • FY23 cash unit; below threshold • FY23 net G&A; between threshold and target Project & asset management (15%) • OGPP operatorship effective 22 May 2023; at threshold; integration spend < budget; at target • BMG spend and timing; below target as at Result: 0/15.00 Growth & portfolio management (15%) Result: 4.72/15.00 People, culture & enablers (20%) Result: 0/20.00 30 June 2023 • OP3D FID delayed by - partner alignment and Govt energy policy; below threshold • Otway exploration select phase; at threshold • Reserve replacement; below threshold, 2C and prospective resource additions; above target • Gippsland asset value plan; at threshold • Term GSA with AGL to support OP3D; at target • Assessing new add value opportunities; at threshold • Employee survey deferred • Gippsland funding plan incorporated into value plan; at threshold • OGPP IT systems integrated; at threshold • IT improvement plan; at target • Constructive engagement on Gas Code and PRRT FY23 performance 21.4 / 100 74 COOPER ENERGY ANNUAL REPORT 2023Directors’ Statutory Report For the year ended 30 June 2023 4.6.3 STIP performance outcomes – Individual results The Board determined that there will be no STIP payment for FY23 as it relates to Company performance, as overall targets set within the corporate scorecard were not satisfied to a level that payment was justified. The Board determined that STIP relating to individual performance measures would be awarded to KMP, and staff generally, based on achievement against individual objectives. The FY23 STIP outcomes for the Executive KMP are shown in the table below: KMP short term incentive (STIP) for the year ended 30 June 2023 STIP - % of Fixed annual remuneration at target STIP - % of fixed annual remuneration at maximum Cash STIP $ % earned of maximum STIP opportunity % forfeited of maximum STIP opportunity 62.5% 25.0% 25.0% 25.0% 25.0% 25.0% 50.0% 25.0% 25.0% 125% 50% 50% 50% 50% 50% 100% 50% 50% 57,144 61,824 45,360 37,440 50,490 34,020 150,000 38,250 - 20.25% 23.70% 20.25% 15.60% 20.40% 21.60% 15.72% 15.30% 0.00% 79.75% 76.30% 79.75% 84.40% 79.60% 78.40% 84.28% 84.70% N/M Executive KMP Ms. J. Norman¹ Mr. D Young² Mr E. Glavas Mr. I. MacDougall Mr. A. Thomas Mr. A. Haren Former Executive KMP Mr. D. Maxwell³ Mr. M. Jacobsen4 Ms. A. Jalleh5 1 Ms. Norman commenced on 20 March 2023. STIP projected to a full year would represent $202,500 gross or 20.25% of her maximum annual STIP opportunity. 2 Mr. Young received an additional STIP payment of $10,304 relating to the months of May and June 2022 (FY22). Mr. Young commenced on 2 May 2022 and received no STIP payment in FY22 pursuant to customary probationary arrangements in his appointment. Part of his employment conditions stated that his FY23 STIP would include a STIP calculation based on 14 months service using his individual performance for the full year of FY23. Mr. Young received a total STIP payment for FY23 of $72,128 gross. 3 Mr Maxwell stood down from the role of Managing Director effective from 20 March 2023. His FY23 STIP award includes the ”personal scorecard” outcome for the period from 20 March to 3 July 2023 when he had stepped down as Managing Director but was still employed. 4 Mr Jacobsen stood down from the role of General Manager Project & Operations effective from 24 April 2023. His FY23 STIP award includes the ”personal scorecard” outcome for the full financial year. 5 Ms Jalleh resigned effective 19 May 2023 and was not entitled to any STIP payment from FY23. 75 COOPER ENERGY ANNUAL REPORT 2023Directors’ Statutory Report For the year ended 30 June 2023 Managing Director & CEO individual performance Jane Norman, Managing Director and CEO, was appointed 20 March 2023; Jane therefore worked 28.22% of FY23. Jane’s STIP maximum opportunity is 125% of her Fixed Annual Remuneration (FAR) currently $800,000 gross per annum. The Board determined a FY23 STIP payment of $57,144 gross will be payable in October 2023 calculated as follows: Ms. J Norman Corporate scorecard Individual performance Total Maximum Eligibility % FAR Maximum Eligibility $ FY23 Result % 93.75% 31.25% 750,000 250,000 125.00% 1,000,000 0% 81% Annualised FY23 Result $ 0 202,500 202,500 Time Worked in FY23 % FY23 Gross STIP Payment $ 28.22% 28.22% 28.22% 0 57,144 57,144 Individual performance was assessed by the Board as follows: Individual FY23 Performance Measures Performance Comments FY23 Outcome Threshold Target Maximum Plans to achieve sustainable improvement of production levels at Orbost Gas Processing Plant (OGPP). Weighting 50% • MHFL transferred 22 May 2023. • Delivery of phase 1 and 2 integration action plans achieved. • Integration of OGPP employees achieved. • Organisational structure change to improve OGPP support in place. • Improvement plan established with actions commenced. • No reportable safety or environmental incidents. BMG decommissioning execution plan in place to deliver a safe and cost- effective project on schedule. Weighting 20% Positive platform established with all key stakeholders. Weighting 20% Organisational structure change established to achieve clear channels of accountability. Weighting 10% • Leadership and team assembled to deliver project execution plan. • Cost estimates in-line with updated FY24 budget. • Plans including training, in place to mitigate safety and environmental risk. • Clear channels of communication in place with service providers and industry colleagues aimed at successful cost and schedule delivery. • Clear communication with all stakeholders on business priorities and delivery outcomes. • Clear articulation on impact of mandatory Gas Code • Well established relationships with key customers and joint venture partners including future arrangements relating to OP3D. • Revised management team to ensure clear, single point accountability on business imperatives. • Revised structure to ensure business is fit for purpose. • Actions commenced to reduce G&A costs. • Incentives review commenced to ensure alignment of company performance and shareholder interests. 76 COOPER ENERGY ANNUAL REPORT 2023Directors’ Statutory Report For the year ended 30 June 2023 Other Executive Key Management Personnel Individual Performance STIP for other Executive KPMP has a 70% weighting on the corporate scorecard and 30% individual performance weighting. Commentary on individual performance and FY23 STIP outcomes follow: D Young Chief Financial Officer • Advanced financial strategy, growing commercial culture • Enhanced financial disclosures, reporting and IR • New enlarged and broadened senior secured bank debt facility • Transformation programme underway including G&A reduction • Company safety, environment and diversity E Glavas General Manager Commercial & Development • New gas contract for OP3D in place • Managed company position on Federal Gas Code • New Commercial team in place • Strategy for Offshore Otway & Gippsland basins in place • Company safety, environment and diversity targets achieved targets achieved Company performance Individual performance FY23 STIP outcome as % of maximum 0% 79.00% 23.70% Company performance Individual performance FY23 STIP outcome as % of maximum 0% 67.50% 20.25% I MacDougall General Manager HSE, Technical Services & IT A Thomas General Manager Exploration & Subsurface and Projects • Delivering sustainability initiatives • IT improvement plan on target • BMG safety and environmental plans in place • Engineering support increased including structural change • Company safety, environment and diversity • Increased 2C and Prospective Resources • Project responsibility absorbed into role • BMG decommissioning project ready to proceed • Contracted drilling rig for OP3D • Company safety, environment and diversity targets achieved Company performance Individual performance FY23 STIP outcome as % of maximum 0% 52.00% 15.60% targets achieved Company performance Individual performance FY23 STIP outcome as % of maximum 0% 68.00% 20.40% A Haren General Manager People & Remuneration • Integration of OGPP employees, phase 1 & 2 achieved • Increased Engineering support established with central base • New industrial instruments in place • Revised organisational structure and leadership team in place • Company safety, environment and diversity targets achieved Company performance Individual performance FY23 STIP outcome as % of maximum 0% 72.00% 21.60% Former Executive key management personnel individual performance D Maxwell Former Managing Director M Jacobsen Former General Manager Projects & Operations • MHFL transferred to OGPP 22 May 2023 • OGPP integration costs under budget • Effective transition to new Managing Director • Workforce collaboration consistent with “one team” ethos • Company safety, environment and diversity • MHFL transferred to OGPP 22 May 2023 • OGPP integration costs under budget • OP3D initial planning completed • BMG decommissioning resourcing in place • Company safety, environment and diversity targets achieved Company performance Individual performance FY23 STIP outcome as % of maximum 0% 62.88% 15.72% targets achieved Company performance Individual performance FY23 STIP outcome as % of maximum 0% 51.00% 15.30% 77 COOPER ENERGY ANNUAL REPORT 2023Directors’ Statutory Report For the year ended 30 June 2023 4.6.4 LTIP outcome The Company’s RTSR compared to the peer group is set out below for the December 2019 LTIP grant that vested in December 2022. The base for the graph is 10 December 2019, being the grant date of PRs and SARs that were made under the Company’s EIP. The terms of the EIP are set out in section 4.4.5. Share price performance of Cooper Energy Limited versus applicable peer group 10 December 2019 to 9 December 2022 -80% -80% -80% -80% -80% -80% -80% -80% -80% -80% -80% -61% Cooper Energy Limited 109% 67% 61% 41% 0% -23% -41% -46% -55% -68% The vesting of the LTIP award in December 2022 was impacted by the performance of the Company’s share price against its peers over the measurement period. Over the three-year measurement period from 10 December 2019 to 9 December 2022, Cooper Energy’s total shareholder return was -61% and it achieved a RTSR percentile rank of 6%. This resulted in a vesting outcome of 0% of all PRs and SARs that were granted in December 2019. In FY23, LTIP grants from 12 December 2018 were re- tested in December 2022. The percentile rank was below the 50th percentile and therefore no shares vested as a result of this re-testing. This was the final re-testing of any grants made under the LTIP. In summary, none of the PRs or SARs granted in December 2018 and December 2019 have vested. There has been no vesting for the past two years of any LTIP. All performance rights and share appreciation rights granted in 2018 and 2019 have lapsed unvested. 78 COOPER ENERGY ANNUAL REPORT 2023Directors’ Statutory Report For the year ended 30 June 2023 4.7 Executive KMP employment contracts Each Executive KMP has an ongoing employment contract. All Executive KMP have termination benefits that are within the allowed limit in the Corporations Act 2001 without shareholder approval. Contracts include the treatment of entitlements on termination in the event of resignation, with notice or for cause. Key terms for each Executive KMP are set out below: Indemnity agreement Treatment on termination by Cooper Energy Notice by Cooper Energy Notice by Executive KMP 6 months 6 months Executive KMP Jane Norman Company provides Indemnity Agreement, Directors and Officers indemnity insurance and access to Company records. 6 months 3 months Other Executive KMP Company provides Indemnity Agreement, Directors and Officers indemnity insurance and access to Company records. Where the Managing Director is not employed for the full period of notice, a payment in lieu may be made. A payment in lieu of notice is based on Fixed Remuneration (base salary and superannuation). Upon termination, superannuation is not paid on accrued annual leave or long service leave. Unused personal leave is not paid out and is forfeited. Where an Executive KMP is not employed for the full period of notice, a payment in lieu may be made. A payment in lieu of notice is based on Fixed Remuneration (base salary and superannuation). Upon termination, superannuation is not paid on accrued annual leave or long service leave. Unused personal leave is not paid out and is forfeited. Under the rules of STIP and the Equity Incentive Plan (EIP) if an Executive KMP ceases employment prior to the vesting date of an Incentive (STIP and LTIP) (e.g., to take a position with another company), they will forfeit all awards. In the case of “qualifying leavers” as defined (examples of which include redundancy, retirement or incapacity), awards may be retained unless the Board determines otherwise. The Board also has a discretion to determine that some or all awards may be retained upon cessation of employment. 79 COOPER ENERGY ANNUAL REPORT 2023Directors’ Statutory Report For the year ended 30 June 2023 4.8 2023 Remuneration outcomes for Executive KMP 4.8.1 Remuneration realised by Executive KMP in FY23 and FY22 (not audited) The Company believes that providing details of the remuneration actually realised by current Executive KMP is useful to shareholders. It provides clear and transparent disclosure of remuneration provided by t he Company. The table set out below shows amounts paid and the cash value of equity awards which vested during the reporting period. It serves to answer the question: what was actually paid as compensation including salary, STIP and LTIP realised in the financial year and any other awards. This information is a non-IFRS measure, and is in addition to and different from the disclosures required by the Corporations Act 2001 and Accounting Standards in the rest of the Remuneration Report including the tables in sections 4.8.2 and 4.9.2. The information in this section 4.8.1 is not audited. The total benefits delivered during the reporting period and set out in the table below comprise the following elements: • FAR is base salary and superannuation (statutory and salary sacrifice). • STIP cash payment made in October each year. The STIP payments shown here correspond to the combined corporate scorecard and individual performance outcomes from the prior financial year. STIP awards are assessed and finalised in August and paid in October, in arrears, for the previous financial year. As a result, the amounts shown in the FY23 row, relate to STIP payments in respect of FY22. These amounts were assessed and approved by the Board in August 2022 and disclosed in 4.6.3 of the remuneration report for the year ended 30 June 2022. The STIP payments shown here align to the financial year when they were actually paid, while the table in section 4.8.2 aligns STIP payments to the financial to which they relate. • LTIP has not realised any vesting in the period stated as none of the partial or full vesting thresholds were met (refer section 4.6.4). Executive KMP Ms J. Norman2 Mr E. Glavas Mr A. Haren Mr I. MacDougall Mr A. Thomas Mr D. Young3 Year 2023 2022 2023 2022 2023 2022 2023 2022 2023 2022 2023 2022 FAR $ STIP1 $ LTIP $ Other $ Total $ 231,017 - - - 448,000 175,552 453,761 36,497 315,000 122,336 301,469 12,526 480,000 189,946 461,874 35,535 495,000 190,519 471,874 40,361 516,065 86,667 - - - - - - - - - - - - - - 401,801 632,818 - - 6,462 630,014 6,284 496,542 6,462 443,798 1,750 315,745 6,462 676,408 6,284 503,693 6,462 691,981 6,284 518,519 66,299 582,364 90,742 177,409 1 The STIP paid in October 2022 (FY23), though it relates to FY22 performance, is included in the 2023 figure as part of remuneration received in FY23. The STIP paid in October 2021 (FY22) is included in the 2022 figure. The table in section 4.8.2 aligns STIP awards with the financial year to which they relate. 2 Ms Norman commenced as an Executive KMP on 20 March 2023 and her entitlements for 2023 are prorated. “Other” remuneration realised includes $400,000 which represents 50% of a sign on bonus. The remaining 50% is payable on the first anniversary of company service. The Company considered this sign on bonus to be a reasonable assessment for the value of incentives forgone from her previous employment. 3 Mr Young’s “Other” remuneration realised included sign on and relocation costs in both 2022 and 2023. The Company considered this sign on bonus to be a reasonable assessment for the value of incentives forgone from his previous employment. 80 COOPER ENERGY ANNUAL REPORT 2023Directors’ Statutory Report For the year ended 30 June 2023 4.8.2 Table of Executive KMP statutory remuneration disclosure for FY23 and FY22 The following table provides IFRS aligned disclosures on KMP remuneration required by the Corporations Act 2001 and Accounting Standards and is audited. By contrast with the table in section 4.8.1, which discloses amounts paid in respect of Executive KMP and the cash value of equity awards which vested during the reporting period, the disclosures provided in the following table present the KMP remuneration costs incurred and accrued during the reporting period. Amounts included as STIP and LTIP in section 4.8.1 represent realised benefits to Executive KMP during the reporting period, whilst the amounts shown in the table below as STIP and LTIP represent benefits incurred during the reporting period (LTIP grants are subject to vesting conditions described in section 4.4.5). Short-term Base Salary STIP1 Other Short-term Benefits2 Long- term Post- employment Share pased remuneration4 Post KMP payments Long Service Base Leave Superannuation3 LTIP Salary11 Severance LTIP12 Total 221,747 57,144 401,801 - - - - - 9,270 - - - - Benefits Executive KMP Ms J. Norman2 Mr E. Glavas Mr A. Haren 2023 2022 2023 2022 2023 2022 422,708 45,360 6,462 14,654 430,193 175,552 6,284 10,582 289,708 34,020 277,901 122,336 6,462 1,750 - - Mr I. MacDougall 2023 454,708 37,440 6,462 13,850 2022 438,306 189,946 6,284 11,499 Mr A. Thomas Mr D. Young6 Former Executive KMP Mr D. Maxwell7 2023 2022 2023 2022 2023 2022 469,708 50,490 6,462 17,940 448,306 190,519 6,284 11,762 490,773 61,824 76,603 82,739 - 90,742 - - 666,573 150,000 47,316 33,656 893,306 818,310 67,523 23,438 Mr M. Jacobsen8 2023 395,590 38,250 Ms A. Jalleh9 Ms V. Suttell10 2022 445,900 194,110 2023 2022 2023 2022 375,229 - 378,151 184,781 - 114,576 - - 410 476 5,934 6,284 - 9,211 13,942 - - - 1,998 (48,282) Totals 2023 3,786,744 474,528 557,912 89,311 2022 3,509,378 1,875,554 187,625 22,941 1Refer to 4.6.3 for STIP amount earned in FY23 which will be paid in FY24. 2Other short-term benefits include fringe benefits on accommodation, car parking, sign on bonuses, relocation and other benefits. Other short term benefits such as short-term compensated absences, short-term cash profit-sharing and other bonuses are not applicable to Executive KMP in FY23. 3Superannuation is the only applicable post-employment benefit ie. No pension or similar benefits for Executive KMP. Superannuation includes the amounts required to be contributed by the Company and does not include amounts salary sacrificed. 4In accordance with the requirements of the Accounting Standards, remuneration includes a proportion of the value of the equity-linked compensation determined as at the grant date of the PRs and progressively expensed over the vesting period. The amount allocated as remuneration is not relative to or indicative of the actual benefit (if any) that may ultimately be realised should the equity instruments vest. The value of the PRs was determined in accordance with AASB 2 Share-based Payments and is discussed in Section 4.8.3 below and in more detail in Note 26 of the Notes to the Financial Statements. 5Ms Norman commenced as an Executive KMP on 20 March 2023 and her entitlements for 2023 are prorated. “Other” remuneration realised includes $400,000 which represents 50% of a sign on bonus. The Company considered this sign on bonus to be a reasonable assessment for the value of incentives forgone from her previous employment. - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 689,962 - 771,798 900,287 453,184 467,329 815,824 945,170 854,378 961,882 892,292 177,409 257,322 254,108 97,702 41,774 278,072 275,567 284,486 281,443 237,800 - 566,677 293,034 - 1,239,071 3,013,857 782,134 - - - 2,608,279 230,335 262,852 319,515 420,132 1,697,372 276,963 241,148 205,393 - (166,612) - - - - - - - - - - - - - - - 954,959 645,496 798,177 - (88,306) 2,193,542 555,886 319,515 1,659,203 9,834,163 1,950,770 - - - 7,725,186 25,292 23,568 25,292 23,568 25,292 23,568 25,292 23,568 25,292 3,928 17,530 23,568 21,077 23,568 23,185 23,568 - 10,014 197,522 178,918 6Mr Young’s “Other” remuneration realised included sign on and relocation costs in both 2022 and 2023. The Company considered this sign on bonus to be a reasonable assessment for the value of incentives forgone from his previous employment. 7Mr Maxwell ceased as an Executive KMP effective from 20 March 2023, but entitlements reflect the full period until his retirement on 3 July 2023. Other includes accommodation costs. 8Mr Jacobsen ceased as an Executive KMP effective from 24 April 2023, but entitlements reflect the full period until his leaving date of 23 October 2023. 9Ms Jalleh ceased to be an Executive KMP on 19 May 2023 and her entitlements for 2023 are prorated. 10 Ms Suttell ceased to be an Executive KMP on 30 September 2021 and her entitlements for 2022 are prorated. 11Includes base salary, other short term benefits and superannuation. 12Relate to LTIP awards made in December 2020, 2021 and 2022 which have not yet been fully expensed as the three-year testing period has not finished. These are non-cash expenses for LTIP grants that have not yet vested. Vesting of these grants remain contingent on the performance hurdles noted in section 4.4.5. No cash-settled share-based payment transactions or other forms of share-based payment compensation (including hybrids) were made by the Company. As noted in section 4.6.4, none of the PRs or SARs scheduled for potential vesting in either FY22 or FY23 – namely PRs and SARs granted in December 2018 and December 2019 – met any partial or full vesting thresholds. As such, all of these PRs and SARs lapsed unvested. 81 COOPER ENERGY ANNUAL REPORT 2023Directors’ Statutory Report For the year ended 30 June 2023 4.8.3 Performance rights and share appreciation rights accounting for the reporting period. The value of the PRs and SARs issued under the Equity Incentive Plan (EIP) is recognised as Share Based Payments in the Company’s statement of comprehensive income and amortised over the vesting period. PRs and SARs were granted under the EIP on 9 December 2022. PRs and SARs are granted for no consideration and employees receive no cash benefit at the time of receiving the rights. shares are issued. Further, the rights can only vest when the RTSR thresholds described in section 4.4.5 have been achieved. PRs and SARs granted under the EIP were valued by an independent consultant applying a Monte Carlo simulation model to determine the probability of achievement of the RTSR against performance conditions. The cash benefit, if any, will be received by the employee following the sale of the resultant shares, but this can only be achieved after the rights have vested and the The value of PRs and SARs shown in the tables below are the accounting fair values for grants in the reporting period: Performance rights (Equity incentive plan) Share appreciation rights (Equity incentive plan) No. of rights granted during period Fair value of rights at grant date No. of rights vested during period % of all rights vested to 30 June 2023 No. of rights granted during period Fair value of rights at grant date No. of rights vested during period % of all rights vested to 30 June 2023 Directors Ms J. Norman Executive KMP Mr E. Glavas Mr A. Haren - - 627,200 84,045 441,000 59,094 Mr I. MacDougall 672,000 90,048 Mr A. Thomas Mr D. Young1 693,000 92,862 1,556,935 250,782 Former Executive KMP Mr D. Maxwell2 1,908,000 255,672 Mr M. Jacobsen3 700,000 93,800 Ms A. Jalleh4 627,200 84,045 - - - - - - - - - - - - 25% 1,668,086 106,758 0% 1,172,873 75,064 28% 1,787,235 114,383 28% 1,843,086 117,958 0% 4,542,590 340,126 29% 5,074,470 324,766 7% 1,861,703 119,149 0% 1,668,086 106,758 - - - - - - - - - - 23% 0% 27% 27% 0% 27% 6% 0% 1 Mr. Young commenced on 2 May 2022 and received no LTIP grant in FY22 pursuant to customary probationary arrangements. As part of the terms of his appointment Mr Young was included in the December 2021 LTIP grant, which was made in FY23 following the completion of his probationary period. 2 Mr Maxwell ceased as an Executive KMP effective from 20 March 2023. 3 Mr Jacobsen ceased as an Executive KMP effective from 24 April 2023. 4 Ms Jalleh ceased as an Executive KMP on 19 May 2023. The vesting date of the PRs granted on 9 December 2022 is 9 December 2025. The estimated fair value of these rights is $0.134 per right and the share price on grant date was $0.195. The performance period for these PRs commenced on 9 December 2022. The vesting date of the SARs granted on 9 December 2022 is 9 December 2025. The estimated fair value of these rights is $0.064 per right and the share price on grant date was $0.195. The performance period for these SARs commenced on 9 December 2022. 82 COOPER ENERGY ANNUAL REPORT 2023 Directors’ Statutory Report For the year ended 30 June 2023 4.8.4 Movement in incentive rights The movement during the reporting period in the number of PRs granted but not exercisable over ordinary shares in Cooper Energy held, directly, indirectly or beneficially, by each Executive KMP, including their related parties, is as follows: Performance rights (Equity incentive plan) Directors Ms J. Norman Executive KMP Mr E. Glavas Mr A. Haren Mr I. MacDougall Mr A. Thomas Mr D. Young1 Former Executive KMP Mr D. Maxwell2 Mr M. Jacobsen3 Ms A. Jalleh4 Held at 1 July 2022 Granted Lapsed Vested & exercised Held at 30 June 2023 - - - 1,665,928 481,607 1,808,599 1,846,735 627,200 441,000 672,000 693,000 - 1,556,935 561,211 613,150 625,363 5,129,370 1,908,000 1,736,571 1,824,695 1,263,109 700,000 627,200 613,150 1,890,309 - 1,731,917 922,607 1,867,449 1,914,372 1,556,935 5,300,799 1,911,545 - - - - - - - - - - SARs represent the right to receive a quantity of shares based on an amount equal to the difference in share price at grant date and test date. The movement during the reporting period in the number of SARs granted but not exercisable over ordinary shares in Cooper Energy held, directly, indirectly or beneficially, by each Executive KMP, including their related parties, is as follows: Share appreciation rights (Equity incentive plan) Directors Ms J. Norman Executive KMP Mr E. Glavas Mr A. Haren Mr I. MacDougall Mr A. Thomas Mr D. Young1 Former Executive KMP Mr D. Maxwell2 Mr M. Jacobsen3 Ms A. Jalleh4 Held at 1 July 2022 Granted Lapsed Vested & exercised Held at 30 June 2023 - - - 5,226,649 1,668,086 1,727,602 1,515,000 1,172,873 5,671,891 1,787,235 1,885,458 5,791,951 1,843,086 1,923,408 - 4,542,590 - 16,088,384 5,074,470 5,342,039 5,722,522 1,861,703 1,885,458 4,074,680 1,668,086 5,742,766 - - - - - - - - - - 5,167,133 2,687,873 5,573,668 5,711,629 4,452,590 15,820,815 5,698,767 - 1 Mr. Young commenced on 2 May 2022 and received no LTIP grant in FY22 pursuant to customary probationary arrangements. As part of the terms of his appointment Mr Young was included in the December 2021 LTIP grant, which was made in FY23 following the completion of his probationary period. 2 Mr Maxwell ceased as an Executive KMP effective from 20 March 2023. 3 Mr Jacobsen ceased as an Executive KMP effective from 24 April 2023. 4 Ms Jalleh ceased as an Executive KMP on 19 May 2023. 83 COOPER ENERGY ANNUAL REPORT 2023 Directors’ Statutory Report For the year ended 30 June 2023 4.8.5 Directors & Executives movement in shares The movement during the reporting period in the number of ordinary shares in Cooper Energy held, directly, indirectly or beneficially, by each KMP, including their related parties, is as follows: Ordinary Shares Directors Mr J. Conde AO Ms J. Norman Ms E. Donaghey Mr J. Schneider Mr T. Bednall Ms V. Binns Ms G. Collins Former Non Executive KMP Mr H. Gordon1 Executive KMP Mr E. Glavas Mr A. Haren Mr I. MacDougall Mr A. Thomas Mr D. Young Former Executive KMP Mr D. Maxwell2 Mr M. Jacobsen3 Ms A. Jalleh4 Held at 1 July 2022 Purchases Received on vesting of PRs & SARs Sales Held at 30 June 2023 859,093 1,045,161 - - 580,000 299,000 1,016,594 1,406,638 132,499 322,857 - 138,000 129,142 160,000 1,746,138 61,224 1,424,203 - 3,474,127 5,147,308 - - - 200,000 816,325 - 20,000,086 3,228,944 297,283 115,770 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 1,904,254 - 879,000 2,423,232 270,499 451,999 160,000 1,807,362 1,424,203 - 3,674,127 5,963,633 - 23,229,030 413,053 - ¹Mr Gordon retired effective 23 June 2023. 2Mr Maxwell ceased as an Executive KMP effective from 20 March 2023. ³Mr Jacobsen ceased as an Executive KMP effective from 24 April 2023. 4Ms Jalleh ceased as an Executive KMP on 19 May 2023. Options No options were issued (or forfeited) during the year. 4.9 Nature of Non-Executive director remuneration Non-Executive Directors are remunerated solely by way of fees and statutory superannuation. Their remuneration is reviewed annually to ensure that the fees reflect their responsibilities and the demands placed on them. Non- Executive Directors do not receive any performance- related remuneration. 4.9.1 Non-Executive Director fee structure The maximum aggregate remuneration pool for Non- Executive Directors, as approved by shareholders at the Company’s 2018 Annual General Meeting, is $1.25 million. The Non-Executive Directors’ fee structure for the reporting period was as follows: 84 COOPER ENERGY ANNUAL REPORT 2023 Directors’ Statutory Report For the year ended 30 June 2023 Role Chairman* Member Board Fee $240,000 $115,000 Audit Committee $20,000 $10,000 Risk & Sustainability Committee People & Remuneration Committee Governance & Nomination Committee $20,000 $10,000 $20,000 $10,000 $0 $10,000 *Where the Chairman of the Board is a member of a committee, he will not receive any additional committee fees. The above Board Fee was set on 1 July 2019 and there has been no increase since that time. Remuneration paid to the Non-Executive Directors for the reporting period and for the previous reporting period is shown in the table in Section 4.9.2. The Company has entered into written letters of appointment with its Non-Executive Directors. The term of the appointment of a Non-Executive Director is determined in accordance with the Company’s Constitution and is subject to the provisions of the Constitution dealing with retirement, re-election and removal of Non-Executive Directors. The Constitution provides that all Non-Executive Directors of the Company are subject to re-election by shareholders by rotation every three years. The Company has entered into indemnity, insurance and access agreements with each of the Non-Executive Directors under which the Company will, on the terms set out in the agreement, provide an indemnity, maintain an appropriate level of Directors’ and Officers’ indemnity insurance and provide access to Company records. 4.9.2 Table of Non-Executive KMP remuneration for 2023 and 2022 financial years Short-term Long- term Post-employment Share based remuneration4 Fees $ STIP1 $ Other short-term benefits2 $ Long service leave $ Superannuation3 $ LTIP $ Total 218,182 218,182 131,818 132,417 136,818 133,015 122,727 106,562 131,818 132,417 136,818 131,818 131,818 132,417 1,010,000 986,828 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 22,909 21,818 13,841 13,242 14,366 13,301 12,886 10,656 13,841 13,242 14,366 13,182 13,841 13,242 106,050 96,683 - - - - - - - - - - - - - - 241,091 240,000 145,659 145,569 151,184 146,316 135,613 117,218 145,659 145,659 151,184 145,000 145,659 145,659 - 1,116,050 - 1,085,511 Directors Mr J. Conde AO Mr T. Bednall Ms V. Binns Ms G. Collins5 Ms E. Donaghey Mr H. Gordon6 Mr J. Schneider Totals 2023 2022 2023 2022 2023 2022 2023 2022 2023 2022 2023 2022 2023 2022 2023 2022 1The STIP values noted for 2022 include an under/over accrual representing the difference between the prior period accrual and what was actually paid in respect of that year. Refer to 4.6.3 for STIP amount earned in FY23 which will be paid in FY24. 2Other short-term benefits include fringe benefits on accommodation, car parking and other benefits. 3Superannuation includes the amounts required to be contributed by the Company and does not include amounts salary sacrificed. 4In accordance with the requirements of the Accounting Standards, remuneration includes a proportion of the value of the equity-linked compensation determined as at the grant date of the PRs and progressively expensed over the vesting period. The amount allocated as remuneration is not relative to or indicative of the actual benefit (if any) that may ultimately be realised should the equity instruments vest. The value of the PRs was determined in accordance with AASB 2 Share-based Payments and is discussed in Section 4.8.3 above and in more detail in Note 27 of the Notes to the Financial Statements. 5Ms Collins commenced on the Board effective 19 August 202. Her 2022 benefits are pro-rated. 6Mr Gordon stepped down from the Board effective 23 June 2023. End of remuneration report. 85 COOPER ENERGY ANNUAL REPORT 2023Directors’ Statutory Report For the year ended 30 June 2023 5. Principal activities Cooper Energy is an upstream gas and oil exploration and production company whose primary purpose is to secure, find, develop, produce and sell hydrocarbons. These activities are undertaken either solely or via unincorporated joint ventures. There was no significant change in the nature of these activities during the year. 6. Operating and financial review Information on the operations and financial position of Cooper Energy and its business strategies and prospects is set out in the Operating and Financial Review. 7. Dividends The Directors do not recommend the payment of a dividend and no amount has been paid or declared by way of dividends since the end of the previous financial year, or to the date of this report. 8. Environmental regulation The Company is a party to various exploration, development and production licences or permits. In most cases, the licence or permit terms specify the environmental regulations applicable to gas and oil operations in the respective jurisdiction. The Group aims to ensure that it complies with the identified regulatory requirements in each jurisdiction in which it operates. There have been no significant known breaches of the environmental obligations of the Group’s licences or permits. 9. Likely developments Other than disclosed elsewhere in the Financial Report (including the Operating and Financial Review under the heading “Outlook”), further information about likely developments in the operations of the Group and the expected results of those operations in future financial years has not been included in this report because disclosure of the information would likely result in unreasonable prejudice to the consolidated entity. 10. Directors’ interests The relevant interest of each Director in ordinary shares and options over shares issued by the parent entity as notified by the Directors to the Australian Stock Exchange in accordance with S205G(1) of the Corporations Act 2001, at the date of this reports is as follows: Ordinary Shares Performance Rights Share Appreciation Rights Mr J. Conde AO 1,904,254 Ms J. Norman Nil Mr T. Bednall Ms V. Binns 270,499 451,999 Ms G. Collins 160,000 Ms E. Donaghey Mr J. Schneider 879,000 2,423,232 Nil Nil Nil Nil Nil Nil Nil Nil Nil Nil Nil Nil Nil Nil Mr D. Maxwell1 23,229,030 5,300,799 15,820,815 Mr H. Gordon2 1,807,362 Nil Nil 1Mr Maxwell stepped down from the Board effective from 20 March 2023 2Mr Gordon stepped down from the Board effective 23 June 2023. 11. Share options and rights At the date of this report, there are no unissued ordinary shares of the parent entity under option. At the date of this report, there are 28,694,792 outstanding PRs and 60,807,624 SARs under the Equity Incentive Plan approved by shareholders at the 2022 AGM. During the financial year no shares were issued as a result of PRs and SARs exercised. At the date of this report, no PRs have vested and been exercised subsequent to 30 June 2023. 12. Events after financial reporting date Refer to Note 29 of the Notes to the Financial Statements. 13. Proceedings on behalf of the Company No person has applied to the Court under section 237 of the Corporations Act 2001 for leave to bring proceedings on behalf of the Company, or to intervene in any proceedings to which the Company is a party for the purpose of taking responsibility on behalf of the Company for all or part of the proceedings. 86 COOPER ENERGY ANNUAL REPORT 2023Directors’ Statutory Report For the year ended 30 June 2023 general standard of independence for auditors imposed by the Corporations Act 2001. The nature and scope of each type of non-audit service provided means that auditor independence was not compromised. 18. Audit tender Ernst & Young have been the Company’s auditors for over ten years and it is anticipated that they will continue in that role for the financial year ended 30 June 2024. The Directors have elected to put the Group’s audit out to tender, with effect from the financial year ended 30 June 2025. It is planned for the tender to be conducted in the course of H2 FY24, with any resultant change, if applicable, to be put to shareholders at the November 2024 AGM. 19. Rounding The Group is of a kind referred to in ASIC Corporations (Rounding in Financial/Directors’ Reports) Instrument 2016/191 dated 24 March 2016 and in accordance with that Legislative Instrument, amounts in the financial report have been rounded to the nearest thousand dollars, unless otherwise stated. This report is made in accordance with a resolution of the Directors. Mr John C. Conde AO Chairman Ms Jane L. Norman Managing Director & CEO Dated at Adelaide 29 August 2023 14. Indemnification and insurance of directors and officers 14.1 Indemnification The parent entity has agreed to indemnify the current Directors and Officers, and past Directors and Officers, of the parent entity and its subsidiaries, where applicable, against all liabilities (subject to certain limited exclusions) to persons (other than the parent entity and its subsidiaries) which arise out of the performance of their normal duties as a Director or Officer, unless the liability relates to conduct involving a lack of good faith. The parent entity has agreed to indemnify the Directors and Officers against all costs and expenses (other than certain excluded legal costs) incurred in defending an action that falls within the scope of the indemnity and any resulting payments. 14.2 Insurance premiums During the financial year, the parent entity has paid insurance premiums in respect of Directors’ and Officers’ liability and legal insurance contracts for current and former Directors and Officers of the parent entity. The insurance contracts relate to costs and expenses incurred by the relevant Directors and Officers in defending proceedings, whether civil or criminal and whatever their outcome and other liabilities that may arise from their position, with exceptions including conduct involving a wilful breach of duty or improper use of information or position to gain a personal advantage. The insurance contracts outlined above do not contain details of premiums paid in respect of individual Directors or Officers of the parent entity. 15. Indemnification of auditors To the extent permitted by law, the Company has agreed to indemnify its auditors, Ernst & Young, as part of the terms of its audit engagement agreement against claims by third parties arising from the audit (for an unspecified amount) except in the case where the claim arises because of Ernst & Young's negligent, wrongful or wilful acts or omissions. No payment has been made to indemnify Ernst & Young during or since the financial year. 16. Auditor’s independence declaration The auditor’s independence declaration is set out on page 99 and forms part of the Directors’ report for the financial year ended 30 June 2023. 17. Non-audit services The amounts paid and payable to the auditor of the Group, Ernst & Young and its related practices for non- audit services provided during the year was $49,500 (2022: $347,100). The directors are satisfied that the provision of non-audit services is compatible with the 87 COOPER ENERGY ANNUAL REPORT 2023Consolidated Statement of Comprehensive Income For the year ended 30 June 2023 Revenue from gas and oil sales Cost of sales Gross profit Other expenses Finance income Finance costs Loss before tax Income tax benefit Petroleum resource rent tax benefit Total tax benefit Notes 2 2 2 18 18 3 3 2023 $'000 2022 $'000 196,885 205,389 (164,379) (157,628) 32,506 47,761 (110,722) (56,857) 3,019 (29,496) (104,693) 28,063 8,167 36,230 468 (14,099) (22,727) 6,057 6,112 12,169 Loss after tax for the period attributable to shareholders (68,463) (10,558) Other comprehensive income/(expenditure) Items that will not be reclassified subsequently to profit or loss Fair value movement on equity instruments at fair value through other comprehensive income 19 648 (332) Other comprehensive income/(expenditure) for the period net of tax 648 (332) Total comprehensive loss for the period attributable to shareholders (67,815) (10,890) Basic loss per share Diluted loss per share 4 4 Cents (2.6) (2.6) Cents (0.6) (0.6) The above Consolidated Statement of Comprehensive Income should be read in conjunction with the accompanying notes. 88 COOPER ENERGY ANNUAL REPORT 2023 Consolidated Statement of Financial Position For the year ended 30 June 2023 Notes 2023 $'000 2022 $'000 Assets Current assets Cash and cash equivalents Trade and other receivables Prepayments Inventory Total current assets Non-current assets Other financial assets Contract asset Property, plant and equipment Intangible assets Right-of-use assets Exploration and evaluation assets Gas and oil assets Deferred tax asset Deferred petroleum resource rent tax asset Total non-current assets Exploration assets classified as held for sale Total sssets Liabilities Current liabilities Trade and other payables Provisions Lease liabilities Interest bearing loans and borrowings Total Current liabilities Non-Current liabilities Trade and other payables Provisions Lease liabilities Interest bearing loans and borrowings Other financial liabilities Deferred petroleum resource rent tax liability Total non-current liabilities Liabilities directly associated with assets held for sale Total liabilities Net assets Equity Contributed equity Reserves Accumulated losses Total Equity 5 6 7 8 20 2 10 11 16 12 13 3 3 9 15 16 17 9 15 16 17 20 3 19 19 77,134 28,797 6,303 2,182 114,416 1,131 2,323 380,375 967 7,448 184,569 535,842 92,643 24,659 1,229,957 247,012 30,467 12,854 841 291,174 484 2,062 59,232 1,360 7,520 164,909 595,347 63,563 12,763 907,240 - 1,558 1,344,373 1,199,972 68,679 166,098 1,467 - 236,244 19,262 417,509 9,182 143,956 2,853 18,494 611,256 32,752 29,867 1,251 37,000 100,870 - 446,754 9,612 121,000 3,285 19,118 599,769 - 908 847,500 701,547 496,873 498,425 716,726 26,071 (245,924) 496,873 478,261 197,625 (177,461) 498,425 The above Consolidated Statement of Comprehensive Income should be read in conjunction with the accompanying notes. 89 COOPER ENERGY ANNUAL REPORT 2023 Consolidated Statement of Changes in Equity For the year ended 30 June 2023 Notes Issued Capital $’000 Reserves $’000 Accumulated Losses $’000 Total Equity $’000 Balance at 1 July 2022 478,261 197,625 (177,461) 498,425 Loss for the period Other comprehensive income Total comprehensive loss for the period - - - - 648 648 (68,463) (68,463) - 648 (68,463) (67,815) Transactions with owners in their capacity as owners: Equity issue Share based payments Transferred to retained earnings Transferred to issued capital Balance as at 30 June 2023 19 19 19 19 58,596 - - - 7,667 - 179,869 (179,869) - - - - 58,596 7,667 - - 716,726 26,071 (245,924) 496,873 Balance at 1 July 2021 477,675 14,118 (165,997) 325,796 Loss for the period Other comprehensive expenditure Total comprehensive loss for the period Transactions with owners in their capacity as owners: Equity issue Share based payments Transferred to retained earnings Transferred to issued capital Balance as at 30 June 2022 - - - - - - 586 19 19 19 19 - (10,558) (10,558) (332) - (332) (332) (10,558) (10,890) 179,508 4,011 906 (586) - - 179,508 4,011 (906) - - - 478,261 197,625 (177,461) 498,425 The above Consolidated Statement of Changes in Equity should be read in conjunction with the accompanying notes. 90 COOPER ENERGY ANNUAL REPORT 2023Consolidated Statement of Cash Flows For the year ended 30 June 2023 Cash flows from operating activities Receipts from customers Payments to suppliers and employees Payments for restoration Petroleum resource rent tax paid Interest received Interest paid Net cash from operating activities Cash flows from investing activities Payments for property, plant and equipment Payments for intangibles Payments for exploration and evaluation Payments for gas and oil assets Proceeds from sale of equity instruments Proceeds from held for sale assets Net cash flows used in investing activities Cash flows from financing activities Repayment of principal portion of lease liabilities Proceeds from equity issue Proceeds from borrowings Repayment of borrowings Transaction costs associated with borrowings Net cash flow from financing activities Net (decrease)/increase in cash held Net foreign exchange differences Cash and cash equivalents at 1 July Cash and cash equivalents at 30 June Notes 2023 $'000 2022 $'000 198,265 204,205 (101,632) (130,156) (19,580) (6,123) (6,225) 2,910 (10,974) 62,764 (245,370) (1,092) (23,248) (5,858) - 650 (925) 419 (9,638) 57,782 (6,119) (493) (5,120) (9,149) 437 - (274,918) (20,444) (1,262) 57,579 158,000 (1,141) 178,000 - (158,000) (60,000) (15,142) 41,175 - 116,859 (170,979) 154,197 1,101 247,012 77,134 1,507 91,308 247,012 5 5 5 5 5 The above Consolidated Statement of Cash Flows should be read in conjunction with the accompanying notes. 91 COOPER ENERGY ANNUAL REPORT 2023Notes to the Consolidated Financial Statements For the year ended 30 June 2023 Corporate information Funding overview The consolidated financial report of Cooper Energy Limited and its controlled entities (“Cooper Energy”, or “the Group”), for the year ended 30 June 2023, was authorised for issue on 28 August 2023 in accordance with a resolution of the Directors. Cooper Energy Limited is a for profit company limited by shares incorporated and domiciled in Australia whose shares are publicly traded on the Australian Securities Exchange. The nature of the operations and principal activities of the Group are described in the Directors’ Statutory Report and in Note 1. Basis of preparation The financial report is a general-purpose financial report, which has 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”) and International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board. The financial report has also been prepared on a historical cost basis, except for equity instruments measured at fair value through other comprehensive income and other items as set out in the notes indicated as measured at fair value through profit and loss. The financial report is presented in Australian dollars. Under the option available to the Group under ASIC Corporations (Rounding in Financial/Directors’ Reports) Instrument 2016/191, all values are rounded to the nearest thousand dollars ($’000), unless otherwise stated. Australian dollars is the functional currency of Cooper Energy Limited and all of its subsidiaries. Transactions in foreign currencies are initially recorded in the functional currency of the transacting entity at the exchange rates ruling at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies at the reporting date are translated at the rates of exchange prevailing at that date. Exchange differences in the consolidated financial statements are taken to the income statement. Plant acquisition The Company executed a binding asset purchase agreement with APA Group, on 20 June 2022, for the purchase of the OGPP. All conditions precedent to the closing of the transaction were completed by late July and the transaction closed, with Cooper Energy becoming the legal owner of the OGPP, on 28 July 2022. Prior to 28 July 2022, the plant was owned by APA Group with the Company paying a processing toll. The Group holds cash balances of $77.1 million and has drawn debt of $158.0 million as at the end of the reporting period with a further $242.0 million committed, available and undrawn under its senior secured reserve based loan facility. The loan facility has an expected maturity date of September 2027. The Company also has a further $12.3 million availability under the Company’s working capital facility. All debt covenants have been complied with, as of the date of this report. Going concern basis The consolidated financial statements have been prepared on the basis that the Group is a going concern, which contemplates continuity of normal operations and the realisation of assets and settlement of liabilities in the ordinary course of business. The BMG restoration provision has been classified as a current provision, resulting in a net current liability. The Group is well funded to complete the BMG abandonment work, with no near- term maturities on outstanding debt and $242.0 million fully committed and undrawn under the facility. The directors have formed the view that there are reasonable grounds to believe that the Group will continue as a going concern. Basis of consolidation The consolidated financial statements are those of the consolidated entity, comprising Cooper Energy Limited (“the parent entity”) and its controlled entities (“Cooper Energy” or “the Group”). The financial statements of subsidiaries are prepared for the same reporting period as the parent entity, using consistent accounting policies. All inter-company balances and transactions, income and expenses and profit and losses arising from intra-group transactions, have been eliminated in full. Subsidiaries are consolidated from the date on which the Group gains control of the subsidiary and cease to be consolidated from the date on which the Group ceases to control the subsidiary. Significant accounting judgements, estimates and assumptions In the process of applying the Group’s accounting policies, management is required to make judgements, estimates and assumptions that affect the reported amounts in the financial statements. Judgements, estimates and assumptions which are material to specific notes of the financial statements are below: Note 3 Income tax Note 16 Leases Note 13 Gas and oil Note 21 assets Note 14 Impairment Note 26 Interests in joint arrangements Share based payments Note 15 Provisions 92 COOPER ENERGY ANNUAL REPORT 2023Notes to the Consolidated Financial Statements For the year ended 30 June 2023 Judgements, estimates and assumptions which are material to the overall financial statements are below: Significant accounting judgements, estimates and assumptions Determination of recoverable hydrocarbons Estimates of recoverable hydrocarbons impact the asset impairment assessment, depreciation and amortisation rates and decommissioning and restoration provisions. Estimates of recoverable hydrocarbons are evaluated and reported by qualified petroleum reserves and resources evaluators in accordance with the ASX Listing Rules and definitions and guidelines in the Society of Petroleum Engineers (SPE) 2018 Petroleum Resources Management System (PRMS). Recoverable hydrocarbon estimates may change from time to time if any of the forecast assumptions are revised. Climate Change In preparing the financial report, management has considered the impact of climate change and current climate-related legislation. The focus of the Company’s strategy on conventional gas production, located close to market in Southeast Australia, is conducive to lower emissions intensity gas supply. The Company measures and reports its emissions and emissions offsets to maintain its’ carbon neutral¹ position as certified by Climate Active, a partnership between the Australian Government and Australian businesses to drive voluntary climate action, whilst also seeking to reduce its gross emissions. These results are published annually in the Company’s Sustainability Report and are aligned with the Financial Stability Board’s Task Force on Climate-Related Financial Disclosures recommendations on climate-related financial disclosures. The Company continues to monitor climate-related policy and its impact on the financial report. The current impacts of climate change include estimates of a range of economic and climate-related scenarios. This includes market supply and demand profiles, carbon emissions profiles, legal impacts and technological impacts. These are factored into discount rates, commodity price forecasts, and demand and supply profiles, all of which are impacted by the global demand profile of the economy as a whole. The estimates and forecasts used by the Company are in accordance with current climate- related legislation and policy. The impact of climate change is considered in the significant judgements and key estimates in a number of areas in the financial report including: • asset carrying values (exploration and evaluation assets, gas and oil assets) through determination of valuations considered for impairment – refer note 14; • restoration obligations, including the timing of such activities – refer note 15; and • deferred taxes, primarily related to asset carrying values and restoration obligations – refer note 3. The Group continues to monitor climate-related policy and its impact on the Financial Report. New accounting standards and interpretations New standards, interpretations and amendments thereof, adopted by the Group the Group for the annual reporting period ending 30 June 2023 are outlined below. The accounting standard and interpretations relevant to the Group that have recently been issued or amended, but are not yet effective and have not been adopted by No new accounting standards, amendments and interpretations applicable on 1 July 2022 have had a material impact on the Group’s financial statements. ¹Cooper Energy has been certified by Climate Active as a carbon neutral organisation for its Scope-1, Scope-2 and relevant Scope-3 emissions (embedded energy and business travel). See 2023 Sustainability Report for further information. 93 COOPER ENERGY ANNUAL REPORT 2023Notes to the Consolidated Financial Statements For the year ended 30 June 2023 Accounting standards and interpretations issued but not yet effective The accounting standards and interpretations that have recently been issued or amended, but are not yet effective and have not been adopted by the Group for the annual reporting period ending 30 June 2023, are outlined below: AASB 2021-5 Summary Amendments to AASs – Deferred Tax related to Assets and Liabilities arising from a Single Transaction AASB 112 Income Taxes requires entities to account for income tax consequences when economic transactions take place, and not at the time when income tax payments or recoveries are made. Accounting for such tax consequences means entities need to consider the differences between tax rules and the accounting standards. This amendment requires entities to also recognise deferred tax for all temporary differences related to leases, decommissioning, restoration and similar liabilities at the beginning of the earliest comparative period presented. Application Date of the Standard 1 January 2023 Funding and risk management Impact on Consolidated Financial Statements The impact of this accounting standard amendment on the Group is yet to be determined. Notes to the financial statements The notes include information which is required to understand the financial statements and is material and relevant to the operations, financial position and performance of the Group. They include applicable accounting policies applied and significant judgements, estimates and assumptions made. Specific accounting policies are disclosed in the respective notes to the financial statements. The notes are organised into the following sections: Group performance Working capital Capital employed Provides additional information regarding financial statement lines that are most relevant to explaining the Group’s operating performance during the period. Provides additional information regarding financial statement lines that are most relevant to explaining the assets used to generate the Group’s operating performance during the period. Provides additional information regarding financial statement lines that are most relevant to explaining the capital investments made that allows the Group to generate its operating result during the period and liabilities incurred as a result. Provides additional information regarding financial statement lines that are most relevant to explaining the Group’s funding sources. This section also provides information relating to the Group’s exposure to various financial risks, its impact on the financial position and performance of the Group and how these risks are managed. Group structure Summarises how the group structure affects the financial position and performance of the Group as a whole. Other information Includes other information that is disclosed to comply with relevant accounting standards and other pronouncements, but is not directly related to the individual line items in the financial statement. 94 COOPER ENERGY ANNUAL REPORT 2023Notes to the Consolidated Financial Statements For the year ended 30 June 2023 Group Performance 1. Segment reporting Identification of reportable segments and types of activities The Group has identified its reportable segments to be Southeast Australia, Cooper Basin (both based on the nature and geographic location of its assets) and Corporate and Other. This forms the basis of internal Group reporting to the Managing Director who is the chief operating decision maker for the purpose of assessing performance and allocating resources between each segment. Revenue and expenses are allocated by way of their natural expense and income category. Other prospective opportunities are also considered from time to time and, if they are secured, will then be attributed to the segment where they are located, or a new segment will be established. The following are reportable segments: Southeast Australia operated Athena Gas Plant. Revenue is derived from the sale of gas and condensate to six contracted customers and via spot sales. The segment also includes exploration and evaluation and care and maintenance activities ongoing in the Gippsland and Otway basins. Cooper Basin This segment comprises production and sale of crude oil in the Group’s permits within the Cooper Basin, along with exploration and evaluation of additional oil targets. Revenue is derived from the sale of crude oil to, Santos Limited and Beach Energy (Operations) Limited, the two participants in the South Australia Cooper Basin joint venture, and IOR Energy Pty Ltd. Corporate and Other The Corporate residual component includes the revenue and costs associated with the running of the business and includes items which are not directly allocable to the other segments. Accounting policies and inter-segment transactions The Southeast Australia segment primarily consists of the operated Sole producing gas assets and the OGPP, the operated Casino Henry producing gas assets and the The accounting policies used by the Group in reporting segments internally is the same as those contained in the financial statements. Southeast Australia $’000 Cooper Basin $’000 Corporate and Other $’000 Consolidated $’000 30 June 2023 Revenue from gas and oil sales to external customers Total revenue 184,542 184,542 12,343 12,343 - - 196,885 196,885 Segment result before interest, tax, depreciation, amortisation and restoration, exploration and evaluation expense and impairment 113,656 6,484 (27,071) 93,069 Restoration expense Depreciation and amortisation Impairment Net finance costs Profit/(loss) before tax Income tax benefit Petroleum resource rent tax benefit Net profit/(loss) after tax Segment assets Segment liabilities Additions of non-current assets Exploration and evaluation assets Gas and oil assets Property, plant and equipment Intangibles (46,343) (93,450) (26,118) (18,764) (71,019) - 8,167 (62,852) 579,625 676,332 23,835 10,981 (9,765) - - - (2,066) (3,308) - (160) 4,258 - - - (7,553) (37,932) 28,063 - (46,343) (98,824) (26,118) (26,477) (104,693) 28,063 8,167 4,258 (9,869) (68,463) 27,470 5,244 737,278 165,924 1,344,373 847,500 986 3,181 - - - - 402 1,092 1,494 24,821 14,162 (9,363) 1,092 30,712 Total additions of non-current assets 25,051 4,167 The above Consolidated Statement of Changes in Equity should be read in conjunction with the accompanying notes. 95 COOPER ENERGY ANNUAL REPORT 2023Notes to the Consolidated Financial Statements For the year ended 30 June 2023 1. Segment reporting (continued) Southeast Australia $’000 Cooper Basin $’000 Corporate and Other $’000 Consolidated $’000 30 June 2023 Revenue from gas and oil sales to external customers Total revenue 188,139 188,139 17,250 17,250 205,389 205,389 - Segment result before interest, tax, depreciation, amortisation and restoration, exploration and evaluation expense and impairment 69,179 11,045 (16,048) 64,176 Restoration income Exploration and evaluation expense Depreciation and amortisation Net finance costs Profit/(loss) before tax Income tax benefit Petroleum resource rent tax benefit Net profit/(loss) after tax Segment assets Segment liabilities Additions of non-current assets Exploration and evaluation assets Gas and oil assets Property, plant and equipment Intangibles (19,031) (118) (48,831) (13,384) (12,185) - 6,112 (6,073) 547,431 521,080 3,499 73,738 28,302 - - (89) (2,165) (137) 8,654 - - - (2) (3,036) (110) (19,196) 6,057 - (19,031) (209) (54,032) (13,631) (22,727) 6,057 6,112 8,654 (13,139) (10,558) 23,964 5,996 628,577 174,471 1,199,972 701,547 1,927 874 - - - - 4 494 498 5,426 74,612 28,306 494 108,838 Total additions of non-current assets 105,539 2,801 In 2022, revenue from two customers amounted to $97.6 million; and $38.5 million respectively in the Southeast Australia segment. 96 COOPER ENERGY ANNUAL REPORT 2023 Notes to the Consolidated Financial Statements For the year ended 30 June 2023 2. Revenues and expenses Revenues Revenue from gas and oil sales Revenue from contracts with customers Gas revenue from contracts with customers Oil revenue from contracts with customers Total revenue from contracts with customers Other revenue Fair value movement on crude oil receivables Total other revenue Total revenue from gas and oil sales Contract assets related to contracts with customers The Group has recognised the following assets related to contracts with customers. Opening balance Contract assets recognised during the year Unwind of contract asset Closing balance Expenses Cost of sales Production expenses Royalties Third-party product purchases and trading costs Amortisation of gas and oil assets Depreciation of property, plant and equipment Inventory movement Total cost of sales Other expenses Selling expense General administration Depreciation of property, plant and equipment Amortisation of intangibles Depreciation of right-of-use assets Care and maintenance Restoration expense Exploration and evaluation expense Impairment expense Other (including new ventures) OGPP reconfiguration and commissioning works Total other expenses Notes 2023 $'000 2022 $'000 184,542 12,403 196,945 188,138 15,712 203,850 (60) (60) 1,539 1,539 196,885 205,389 2,062 492 (231) 2,323 - 2,062 - 2,062 (61,081) (1,118) (7,604) (58,654) (36,853) 931 (80,362) (1,594) (24,678) (49,443) (1,551) - (164,379) (157,628) (402) (637) (19,063) (14,729) (713) (1,485) (1,119) (2,612) (740) (1,193) (1,105) (2,808) (46,343) (19,031) - (26,118) (12,421) (446) (110,722) (209) - (1,321) (15,084) (56,857) 14 97 COOPER ENERGY ANNUAL REPORT 2023Notes to the Consolidated Financial Statements For the year ended 30 June 2023 2. Revenues and expenses (continued) Employee benefits expense included in general administration Director and employee benefits Share based payments Superannuation expense Total employee benefits expense (gross) Accounting policy Notes 2023 $'000 2022 $'000 (28,960) (26,417) (7,667) (2,365) (4,011) (1,953) (38,992) (32,381) Revenue from contracts with customers Revenue from contracts with customers is recognised at the point in time when control of the natural gas, liquids or crude oil is transferred to the customer, at an amount that reflects the consideration to which the Group expects to be entitled in exchange for those goods. This is generally when the product is transferred to the delivery point specified in the individual customer contract. The Group’s performance obligations are considered to relate only to the sale of the natural gas, liquids or crude oil, with each GJ of natural gas or barrel of liquids or crude oil considered to be a separate performance obligation under the contractual arrangements in place. The Group has concluded that it is the principal in all of its revenue arrangements since it controls the goods before transferring them to the customer. Under the terms of the relevant joint operating arrangements the Group is entitled to its participating share in the natural gas, liquids or crude oil, based on the Group’s entitlement interest. Revenue from contracts with customers is recognised based on the actual volumes sold to customers. The Group’s sales of natural gas are predominantly based on contracted prices, while crude oil and liquids transactions are priced based on crude oil market prices, adjusted for a quality differential. The crude oil sales contain provisional pricing. Revenue from contracts with customers is recognised based on the provisional pricing at the date of delivery, with the price estimate based on the forward curve. The difference between the estimated price and the price ultimately achieved for the sale of the crude oil transaction is recognised as a movement in the fair value of the receivable in accordance with AASB 9 Financial Instruments. This amount is presented as other revenue in Note 2 as these movements are not within the scope of AASB 15 Revenue from Contracts with Customers. Contract assets A contract asset is recognised for gas contracts that have variable selling prices, which are allocated proportionately to all the performance obligations over the life of the contract. Contract assets unwind as “revenue from contracts with customers” with reference to the performance obligation. 98 COOPER ENERGY ANNUAL REPORT 2023Notes to the Consolidated Financial Statements For the year ended 30 June 2023 3. Income tax Consolidated Statement of Comprehensive Income Current income tax Current year Deferred income tax Origination and reversal of temporary differences Recognition of tax losses Income tax benefit Current petroleum resource rent tax Current year Deferred petroleum resource rent tax Origination and reversal of temporary differences Petroleum resource rent tax benefit 2023 $'000 2022 $'000 - - 7,814 20,249 28,063 28,063 (4,184) (4,184) 12,351 12,351 8,167 - - (2,309) 8,366 6,057 6,057 (4,616) (4,616) 10,728 10,728 6,112 Total tax benefit 36,230 12,169 Reconciliation between tax expense and pre-tax net profit Accounting loss before tax from continuing operations Income tax using the domestic corporation tax rate of 30% (2022: 30%) (Increase)/decrease in income tax expense due to: Non-deductible expenditure Recognition of royalty related income tax benefits Other Income tax benefit Petroleum resource rent tax benefit Total tax benefit (104,692) 31,408 (22,727) 6,818 (2,744) (4,520) 3,919 28,063 8,167 36,230 (1,241) (2,487) 2,967 6,057 6,112 12,169 Tax Consolidation Cooper Energy Limited and its 100% owned Australian resident subsidiaries are consolidated for Australian income tax purposes, with Cooper Energy Limited being the head entity of the tax consolidated group. Members of the Group entered into a tax sharing arrangement in order to allocate income tax expense to the wholly-owned subsidiaries. In addition, the agreement provides for the allocation of income tax liabilities between the entities should the head entity default on its tax payment obligations. Members of the tax consolidated group have entered into a tax funding agreement. The tax funding agreement requires members of the tax consolidated group to make contributions to the head company for tax liabilities and deferred tax balances arising from transactions occurring after the implementation of tax consolidation. Contributions are payable following the payment of the liabilities by Cooper Energy Limited. The assets and liabilities arising under the tax funding agreement are recognised as inter-company assets and liabilities with a consequential adjustment to income tax expense or benefit. In addition, the agreement provides for the allocation of income tax liabilities between the entities should the head entity default on its tax payment obligations or upon leaving the Group. The current and deferred tax amounts are measured in a systematic manner that is consistent with the broad principles in AASB 112 Income Taxes. 99 COOPER ENERGY ANNUAL REPORT 2023 Notes to the Consolidated Financial Statements For the year ended 30 June 2023 3. Income Tax (continued) Unrecognised temporary differences At 30 June 2023, there are no unrecognised temporary differences associated with the Group’s investments in subsidiaries, as the Group has no liability for additional taxation should unremitted earnings be remitted (2022: $nil). Franking Tax Credits At 30 June 2023 the parent entity had franking tax credits of $42.9 million (2022: $42.9 million). The fully franked dividend equivalent is $142.9 million (2022: $142.9 million). Petroleum Resource Rent Tax Cooper Energy Limited has recognised a deferred tax liability for PRRT of $18.5 million (2022: $19.1 million) Deferred income tax from corporate tax Deferred income tax at 30 June relates to: Deferred tax liabilities Trade and other receivables Gas and oil assets Exploration and evaluation Other Deferred tax assets Leases Provisions Tax losses Other Deferred tax benefit and a deferred tax asset for PRRT of $24.7 million (2022: $12.8 million). Income Tax Losses (a) Revenue Losses A deferred tax asset has been recognised for the year ended 30 June 2023 of $96.2 million (2022: $76.6 million). (b) Capital Losses Cooper Energy has not recognised a deferred tax asset for Australian income tax capital losses of $15.5 million (2022: $15.5 million) on the basis that it is not probable that the carried forward capital losses will be utilised against future assessable capital profits. Consolidated Statement of Financial Position Consolidated Statement of Comprehensive Income 2023 $'000 2022 $'000 2023 $'000 2022 $'000 57 45,951 29,049 9,701 84,758 3,195 77,148 96,205 853 5,994 49,533 21,921 1,977 79,425 3,259 57,760 76,595 5,374 177,401 142,988 (5,937) (3,582) 7,128 7,724 5,333 (64) 19,388 19,610 (4,521) 34,413 39,746 (77) (3,657) (2,805) (1,738) (8,277) (342) 7,639 10,205 (1,655) 15,847 7,570 Deferred tax asset from corporate tax 92,643 63,563 Deferred income tax from PRRT Deferred income tax at 30 June relates to: Deferred tax liabilities Gas and oil assets Deferred tax liability from PRRT Deferred tax assets Gas and oil assets Deferred tax asset from PRRT Total deferred tax from PRRT 18,494 18,494 24,659 24,659 19,118 19,118 12,763 12,763 (624) - (2,035) - 11,896 12,763 - - 11,272 10,728 100 COOPER ENERGY ANNUAL REPORT 2023 Notes to the Consolidated Financial Statements For the year ended 30 June 2023 3. Income Tax (continued) Accounting policy Current tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from or paid to the taxation authorities, based on tax rates and tax laws that are enacted or substantively enacted by the reporting date. Deferred income tax is recognised on all temporary differences, except for: • • the initial recognition of an asset or liability that affects neither the accounting profit nor taxable profit or loss; or the taxable temporary difference is associated with investments in subsidiaries, associates or interests in joint ventures, and the timing of the reversal of the temporary difference can be controlled and it is probable that the temporary difference will not reverse in the foreseeable future. Deferred income tax assets are recognised for all deductible temporary differences, carry-forward of unused tax assets and unused tax losses, to the extent that it is probable that future taxable profit will be available against which the deductible temporary differences and the carry-forward of unused tax credits and unused tax losses can be utilised. The carrying amount of deferred income tax assets is reviewed at each reporting date and reduced to the extent that it is no longer probable that sufficient taxable profit will be available to allow all or part of the deferred income tax asset to be utilised. Unrecognised deferred income tax assets are reassessed at each reporting date and are recognised to the extent that it has become probable that future taxable profit will allow the deferred tax asset to be recovered. Deferred income tax assets and liabilities are measured at the tax rates that were expected to apply to the year when the asset is realised or the liability is settled, based on tax rates and tax laws that have been enacted or substantively enacted by the reporting date. Income taxes relating to items recognised directly in equity are recognised in equity and not in profit or loss. Deferred tax assets and deferred tax liabilities are offset only if a legally enforceable right exists to offset current tax assets against current tax liabilities and the deferred tax asset and liabilities relate to the same taxable entity and the same taxation authority. Where allowable by initial recognition exemptions, deferred tax assets and deferred tax liabilities that arise on acquisition are not recognised. Petroleum Resource Rent Tax For PRRT purposes, the impact of future augmentation on expenditure is included in the determination of future taxable profits when assessing the extent to which a deferred tax asset can be recognised in the statement of financial position. Deferred tax assets are reduced to the extent that it is no longer probable that the related tax benefit will be realised. Goods and Services Taxes (“GST”) Revenues, expenses and assets are recognised net of the amount of GST. Receivables and payables are stated inclusive of the amount of GST receivable or payable. The net amount of GST recoverable from, or payable to, the taxation authority is included as part of receivables or payables in the Consolidated Statement of Financial Position. Commitments and contingencies are disclosed net of the amount of GST recoverable from, or payable to, the taxation authority. Cash flows are included in the Cash Flow Statement on a net basis and the net GST component of cash flows arising from investing and financing activities, which is recoverable from, or payable to, the taxation authority, are classified as operating cash flows. 101 COOPER ENERGY ANNUAL REPORT 2023Notes to the Consolidated Financial Statements For the year ended 30 June 2023 3. Income Tax (continued) Significant accounting judgements, estimates and assumptions The Group has a Tax Risk Management Framework which outlines how the direct and indirect tax obligations of Cooper Energy Limited are met from an operational, governance and tax risk management perspective. Management judgements are made in relation to the types of arrangements considered to be a tax on income, including PRRT, in contrast to an operating cost. Judgement is also made in assessing whether deferred tax assets and certain deferred tax liabilities are recognised on the Consolidated Statement of Financial Position. Deferred tax assets, including those arising from un-recouped tax losses, capital losses, and temporary differences arising from the PRRT legislation, are recognised only where it is considered more probable they will be recovered, which is dependent on the generation of sufficient future taxable profits. Future taxable profits are estimated by using Board approved internal budgets and forecasts. Judgements are also required about the application of income tax legislation. These judgements and assumptions are subject to risk and uncertainty, hence there is a possibility changes in circumstances will alter expectation, which may impact the amount of deferred tax assets and deferred tax liabilities recognised on the Consolidated Statement of Financial Position and the amount of other tax losses and temporary differences not yet recognised. In such circumstances, some or all of the carrying amounts of recognised deferred tax assets and liabilities may require adjustment, resulting in a corresponding credit or charge to the Consolidated Statement of Comprehensive Income. 4. Earnings per share The following reflects the net loss and share data used in the calculations of earnings per share: Net loss after tax attributable to shareholders 2023 $'000 2022 $'000 (68,463) (10,558) 2023 Thousands 2022 Thousands Weighted average number of ordinary shares used in calculating basic earnings per share 2,621,292 1,646,285 Dilutive performance rights and share appreciation rights¹ - Weighted average number of ordinary shares used in calculating dilutive earnings per share 2,621,292 1,646,285 Basic loss per share for the period (cents per share) Diluted loss per share for the period (cents per share) (2.6) (2.6) (0.6) (0.6) ¹The weighted average number of potentially dilutive shares at 30 June 2023 is 28.9 million (2022: 24.3 million) At 30 June 2023 there exist performance rights and share appreciation rights that if vested, would result in the issue of additional ordinary shares over the next three years. In the current period, these potential ordinary shares are considered antidilutive as their conversion to ordinary shares would reduce the loss per share. Accordingly, they have been excluded from the dilutive earnings per share calculation. There have been no other transactions involving ordinary shares or potential ordinary shares between the reporting date and the date of completion of these financial statements. Accounting policy Basic earnings per share are calculated as net profit attributable to shareholders divided by the weighted average number of ordinary shares. Diluted earnings per share is calculated as net profit attributable to shareholders adjusted for the after tax effect of dilutive potential ordinary shares that have been recognised as expenses during the period divided by the weighted average number of ordinary shares and dilutive potential ordinary shares. 102 COOPER ENERGY ANNUAL REPORT 2023Notes to the Consolidated Financial Statements For the year ended 30 June 2023 Working Capital 5. Cash and cash equivalents and term deposits Current Assets Cash at bank and in hand Cash and cash equivalents Reconciliation of net profit to net cash flows from operating activities Net loss after tax Add/(deduct) non-cash items: Amortisation of gas and oil assets Depreciation of property, plant and equipment Amortisation of intangibles Depreciation of right-of-use assets Impairment expense Exploration and evaluation expense Restoration (income)/expense Share based payments Finance costs Foreign exchange (gain)/loss Other non-cash movements Net cash from operating activities before changes in assets or liabilities Add/(deduct) changes in operating assets or liabilities: Increase in trade and other receivables Decrease/(increase) in inventories Increase in prepayments Increase in deferred taxes Increase in trade and other payables Decrease in provisions Net cash from operating activities Reconciliation of liabilities arising from financing activities 2023 $'000 2022 $'000 77,134 77,134 247,012 247,012 (68,463) (10,558) 58,654 37,566 1,485 1,119 26,118 - 46,343 7,667 16,850 (705) (532) 126,102 (1,406) (1,340) 6,527 (37,556) (6,331) (23,232) 62,764 49,443 2,291 1,193 1,105 - 209 19,031 4,011 4,461 (1,527) 22 69,681 (721) 109 (5,255) (16,785) 13,545 (2,792) 57,782 Balance at beginning of period Financing cash flows¹ Other Balance at end of period Borrowings Lease Liabilities 2023 $'000 158,000 (15,142) 1,098 2022 $'000 218,000 (60,000) - 143,956 158,000 2023 $'000 10,863 (1,262) 1,048 10,649 2022 $'000 12,004 (1,141) - 10,863 ¹Financing cash flows consist of the net amount of proceeds from borrowings and repayment of lease liabilities in the statement of cash flows. Accounting policy Cash and cash equivalents in the Consolidated Statement of Financial Position comprise cash at bank and short-term deposits for periods of up to three months or subject to insignificant changes in value. For the purposes of the Statement of Cash Flows, cash and cash equivalents includes cash and term deposits as defined above, net of outstanding bank overdrafts. Cash held in escrow with associated restrictions, whereby the Group cannot use that cash for operational purposes as it deems appropriate, is not included in cash and cash equivalents. 103 COOPER ENERGY ANNUAL REPORT 2023Notes to the Consolidated Financial Statements For the year ended 30 June 2023 6. Trade and other receivables Current Assets Trade receivables Accrued revenue Interest receivable 2023 $'000 2022 $'000 11,360 17,247 190 28,797 10,486 19,901 80 30,467 Expected credit losses in respect of trade and other receivables is set out in Note 20. Accounting policy Trade receivables are non-interest bearing and generally have 30 to 90 day terms. Trade receivables are initially recognised at the transaction price as defined by AASB 15 Revenue from Contracts with Customers and subsequently carried at amortised cost less any allowances for expected credit loss. An allowance for expected credit loss is recognised using the simplified approach which permits the use of the lifetime expected loss provision for all trade receivables. Bad debts are written off when identified. 7. Prepayments Insurance Prepaid cash calls to joint arrangements Prepaid plant acquisition and debt refinancing costs¹ Other prepayments 2023 $'000 4,229 1,970 - 104 2022 $'000 3,463 1,975 6,469 947 6,303 12,854 ¹A portion of this amount relates to transaction costs incurred in 2022 associated with the acquisition of the OGPP which were subsequently capitalised to property, plant and equipment on completion of the acquisition in FY23. It also includes costs associated with the new corporate reserves based loan facility, which upon execution in FY23 were included in the initial measurement of the resulting financial liability. 8. Inventory Petroleum products Spares and parts All inventory items are carried at cost in the current and previous financial years. 9. Trade and other payables Trade payables Deferred consideration1 Accruals (capital and operating expenditure) Non-Current Deferred consideration¹ 2023 $'000 966 1,216 2,182 2023 $'000 6,411 40,000 22,268 68,679 19,262 2022 $'000 - 841 841 2022 $'000 10,506 - 22,246 32,752 ¹Deferred consideration represents the fixed payments due 12 and 24 months after financial close of the OGPP acquisition which occurred on 28 July 2022. The Group records deferred consideration at the present value of consideration payments. Accounting Policy Trade payables are non-interest bearing and carried at amortised cost. The amounts represent liabilities for goods and services provided during the financial year, but not yet settled at the balance sheet date. Accruals represent unbilled goods or services. 104 COOPER ENERGY ANNUAL REPORT 2023Notes to the Consolidated Financial Statements For the year ended 30 June 2023 Capital Employed 10. Property, plant and equipment Reconciliation of carrying amounts at beginning and end of period: Production assets Corporate assets 2023 $'000 2022 $'000 2023 $'000 2022 $'000 Total 2023 $'000 2022 $'000 Carrying amount at beginning of period 55,928 29,177 3,304 4,040 59,232 33,217 Assets acquired¹ Additions Restoration Impairment Depreciation Carrying amount at end of period Cost Accumulated depreciation Carrying amount at end of period 374,016 10,724 (20,489) (5,944) (36,853) 377,382 419,617 (42,235) 377,382 - 6,115 22,187 - (1,551) 55,928 61,306 (5,378) 55,928 - 402 - - (713) 2,993 8,114 (5,121) 2,993 - 4 - - (740) 3,304 7,717 (4,413) 3,304 374,016 11,126 - 6,119 (20,489) 22,187 (5,944) (37,566) 380,375 427,731 (47,356) 380,375 - (2,291) 59,232 69,023 (9,791) 59,232 ¹Acquisition of OGPP includes $210.0 million upfront consideration, $58.1 million deferred consideration, $27.0 million capitalised acquisition and transaction costs and $78.9 million in relation to the restoration obligations acquired. Accounting policy Property, plant and equipment comprises office and IT equipment, leasehold improvements, the OGPP and the Athena Gas Plant, and are stated at historical cost less accumulated depreciation and any accumulated impairment losses (refer to Note 14 for impairment policy). Historical cost includes expenditure that is directly attributable to the acquisition of the items. 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 Group and the cost of the item can be measured reliably. Repairs and maintenance are recognised in the Consolidated Statement of Comprehensive Income as incurred. Depreciation on property plant and equipment is calculated at between 7.5% and 37.5% per annum using the diminishing value method over the respective asset’s estimated useful live. Production assets are depreciated on a units of production basis. The assets’ residual values and useful lives are reviewed, and adjusted if appropriate, at each reporting date. An item of property, plant and equipment is derecognised upon disposal or when no further future economic benefits are expected from its use. Any gains or losses arising on derecognition of the asset (calculated as the difference between the net disposal proceeds and the net carrying amount of the asset) is included in the Consolidated Statement of Comprehensive Income. 11. Intangible assets Reconciliation of carrying amounts at beginning and end of period: Carrying amount at beginning of period Additions Amortisation Carrying amount at end of period Cost Accumulated amortisation Carrying amount at end of period 2023 $'000 2022 $'000 1,360 1,092 (1,485) 967 4,394 (3,427) 967 2,059 494 (1,193) 1,360 3,302 (1,942) 1,360 Accounting Policy Intangible assets comprise software and are stated at historical cost less accumulated amortisation and any accumulated impairment losses. Historical cost includes expenditure that is directly attributable to the acquisition of the items. Intangible assets are determined to have a finite useful life and are amortised over their useful lives and tested for impairment whenever there is an indicator of impairment. Amortisation on intangibles is calculated at 20% per annum using the straight line method. The assets’ residual values and useful lives are reviewed, and adjusted if appropriate, at each reporting date. 105 COOPER ENERGY ANNUAL REPORT 2023Notes to the Consolidated Financial Statements For the year ended 30 June 2023 12. Exploration and evaluation assets Reconciliation of carrying amounts at beginning and end of period: Carrying amount at beginning of period Additions¹ Impairment Exploration and evaluation expense Exploration expenditure classified as held for sale Carrying amount at end of period² Notes 2023 $'000 2022 $'000 14 164,909 159,443 24,821 (5,161) - - 5,426 - (209) 249 184,569 164,909 ¹Additions in 2023 relate to OP3D and licensing and interpretation of 3D seismic data in the Gippsland basin. Additions in 2022 relate to drilling two oil exploration wells in the Cooper Basin and completion of a 3D seismic survey in the Onshore Otway. ² Recoverability is dependent on the successful development and commercial exploration or sale of the respective areas of interest. The sale to Bass Oil Limited of the Company’s interests in several of its Cooper Basin exploration and production licences (PEL 93, PPL 207, PRL 237, PEL 100 and PEL 110) was completed on 1 August 2022 for a consideration of $0.65 million. The assets and associated liabilities were classified as held for sale and presented in separate lines in the Consolidated Statement of Financial Position as at 30 June 2022. Accounting policy Exploration and evaluation expenditure include costs incurred in the search for hydrocarbon resources and determining the 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: a. the rights to tenure of the areas of interest are current and the Group controls the area of interest in which the expenditure has been incurred; and i. such costs are expected to be recouped through successful development and exploration of the area of interest, or alternatively by its sale; or ii. exploration and evaluation activities in the area of interest have not at the reporting date: b. reached a stage which permits a reasonable assessment of the existence or otherwise of economically recoverable reserves; and c. 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 a natural gas or an oil field is considered favourable or has been proven to exist, and in most cases, comprises an individual prospective gas or oil field. Exploration and evaluation expenditure which does not satisfy these criteria is written off. 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 Consolidated 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. Any appraisal costs relating to determining commercial feasibility are also capitalised as exploration and evaluation assets. 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 facts and circumstances suggest that the carrying amount exceeds the recoverable amount, or where one of the specific factors set out in i-ii above are no longer met, the Group will test for impairment in accordance with the impairment policy stated in Note 14. 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 gas or oil field enters the development phase, the accumulated exploration and evaluation expenditure is tested for impairment and then transferred to gas and oil assets. 106 COOPER ENERGY ANNUAL REPORT 2023 Notes to the Consolidated Financial Statements For the year ended 30 June 2023 13. Gas and oil assets Reconciliation of carrying amounts at beginning and end of period: Carrying amount at beginning of period Additions¹ Amortisation Impairment Carrying amount at end of period Cost² Accumulated amortisation & impairment² Carrying amount at end of period Notes 2023 $'000 2022 $'000 14 595,347 14,162 570,178 74,612 (58,654) (49,443) (15,013) 535,842 - 595,347 839,898 834,134 (304,056) (238,787) 535,842 595,347 ¹Updates to restoration provisions have resulted in $9.5 million (2022: $66.7 million) additions to gas and oil assets. Refer to Note 15 for more information. ²Fully written down assets with an original cost of $8.4 million were written-off in their entirety during the period impacting both cost and accumulated depreciation balances. Accounting policy Gas and oil assets are carried at cost including construction, installation of infrastructure such as roads, pipelines or umbilicals and the cost of development of wells. Any restoration assets arising as a result of recognition of a restoration provision are also included in the carrying amount of gas and oil assets. 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 Group and the cost of the item can be measured reliably. All other repairs and maintenance are charged to the Consolidated Statement of Comprehensive Income as incurred. Gas and oil assets are amortised on a units-of-production basis, using the latest approved estimate of reserves and future development cost estimates. Amortisation is charged only once production has commenced. No amortisation is charged on areas under development where production has not commenced. Gas and oil assets are subject to impairment testing, refer to Note 14. Significant accounting judgements, estimates and assumptions Estimation of gas and oil asset expenditure Capitalised gas and oil assets for the construction of major projects or ongoing well construction activities include accruals in relation to the value of work done. These remain estimates until the contractual arrangement is finalised, including any rebates, credits and variations as part of the standard contractual process. Amortisation of gas and oil assets The amortisation of gas and oil assets are impacted by management’s estimates of reserves and future development costs. Refer to the significant accounting judgements, estimates and assumptions section on page 55 in relation to reserves. Future development cost estimates are costs necessary to develop an assets’ undeveloped 2P reserves. These costs are subject to changes in technology, regulation and other external factors. Significant accounting judgements, estimates and assumptions are also made in relation to the impairment of gas and oil assets and recognition of restoration assets, refer to Note 14 and Note 15 respectively. 107 COOPER ENERGY ANNUAL REPORT 2023Notes to the Consolidated Financial Statements For the year ended 30 June 2023 14. Impairment Exploration and evaluation assets Property, plant & equipment Gas and oil assets Total impairment recognised 2023 $'000 5,161 5,944 15,013 26,118 2022 $'000 - - - - As at 30 June 2023, indicators of impairment were present for the Casino Henry Netherby cash generating unit (“CGU”). The combination of the above factors has given rise to the need to formally estimate the CGU’s recoverable amount. The Casino Henry Netherby CGU comprises: • The Casino, Henry and Netherby producing gas fields; recorded within gas and oil assets • The Athena Gas Plant, recorded within property, plant and equipment ; and • The Annie gas field, recorded within exploration and evaluation assets. A number of factors have contributed to the presence of indicators of impairment for the Casino Henry Netherby CGU, including: • delays to approvals for the development of the Annie gas field, as part of the broader OP3D. These delays were due to: • the uncertainties arising from the Federal Government’s gas market intervention, including the new mandatory gas code of conduct • partner misalignment on OP3D • changes to market conditions, including the upward pressures from increased industry activity on certain costs such as drilling rigs, support vessels, helicopter support and other costs impacting not only future developments but also decommissioning costs; and • macro-economic factors such as inflation, cost of financing and foreign exchange assumptions. Gas and oil properties – Casino Henry Netherby Exploration and evaluation – VIC/P44 exploration Property, plant & equipment – Athena Gas Plant Total impairment via FVLCD As part of the amendments to the Sole gas sales agreement (“GSA”) announced in September 2021, the Company agreed to the supply of all developed and uncontracted volumes from the existing Casino Henry and Netherby wells to AGL Energy Limited at the Sole GSA price, with effect from 1 January 2022 until first production from the next phase of development in the Otway Basin. Whilst softer spot market gas pricing has been observed in the short term, forward estimates embedded within the fair value less cost of disposal (“FVLCD”) estimate for the Casino Henry Netherby CGU remain largely in line with FY22. In accordance with the accounting standards, no repurposing of the plant has been assumed; for example, into a gas storage facility, or for carbon capture and storage. This is a conservative position, but appropriate for the impairment assessment. The non-cash impairment loss recognised at June 2023 is a result of the above factors. The impairment loss does not take into account the full value of the OP3D project, nor does it impact the future sanctioning of the project. Recoverable amounts and resulting impairment write- downs recognised in the year ended 30 June 2023 are as follows: Segment Impairment $’000 Southeast Australia 15,013 Southeast Australia Southeast Australia 5,161 5,944 26,118 The FVLCD of the Casino Henry Netherby CGU was determined based on expectations of the estimated future cash flows from both the developed and undeveloped upstream reserves and resources and the Casino Henry Netherby and Annie fields. A post-tax, discount rate of 8.9% has been applied, reflective of the time value of money and risks specific to the asset. The FVLCD model and discount rate are prepared on without incorporating assumptions on future inflation/ on a real basis. Other relevant assumptions are those outlined in the Significant Accounting Judgements, Estimates and Assumptions section that follows. 108 COOPER ENERGY ANNUAL REPORT 2023Notes to the Consolidated Financial Statements For the year ended 30 June 2023 14. Impairment (continued) Changes in key assumptions to which the recoverable amount is most sensitive would result in higher or lower carrying values as follows: Resultant impact on carrying value Uncontracted gas price (+/- $1/GJ) (assumed A$12 real June 2023) Discount rate (+/- 1%) Capital expenditure (+/- 10%) Higher $'000 3,800 1,500 11,900 Lower $'000 (1,500) (400) (9,800) Accounting policy The carrying values of non-current assets, including, property, plant and equipment, capitalised exploration and evaluation assets and gas and oil assets are assessed for indicators of impairment at each reporting date (every six months). Where indicators of impairment are present, an impairment test is performed. An impairment loss is recognised for the amount by which the asset or CGU’s carrying amount exceeds its recoverable amount. The recoverable amount of a non- current asset or CGU is the higher of value in use (“VIU”) and FVLCD. For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash flows. In assessing VIU, the estimated future cash flows are discounted to their present value using a pre-tax rate that reflects the risks specific to the asset. Where the recoverable amount is based on the FVLCD, a discounted cash flow model is also used and the inputs are consistent with level 3 on the fair value hierarchy. The estimated future cash flows are prepared on a real (no estimates for future inflation) basis and discounted to their present value using a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the asset that would be taken into account by an independent market participant. Significant accounting judgements, estimates and assumptions Impairment of exploration and evaluation assets The future recoverability of capitalised exploration and evaluation expenditure is dependent on a number of factors, including whether the Group decides to exploit the related lease itself or, if not, whether it successfully recovers the related exploration and evaluation asset through sale. Management is required to make certain estimates and assumptions in applying this policy. Factors which could impact the future recoverability include the level of gas and oil resources, future technological changes which could impact the cost of extraction, future legal changes (including changes to environmental restoration obligations) and changes to commodity prices. These estimates and assumptions may change as new information becomes available. To the extent that capitalised exploration and evaluation expenditure is determined not to be recoverable in the future, this will reduce profits and net assets in the period in which this determination is made. In addition, exploration and evaluation expenditure is capitalised if activities in the area of interest have not yet reached a stage which permits a reasonable assessment of the existence or otherwise of economically recoverable gas and oil reserves or resources. To the extent that it is determined in the future that this capitalised expenditure should be written off, this will reduce profits and net assets in the period in which this determination is made. Impairment of exploration and evaluation assets and gas and oil assets The Group reviews the carrying amount of gas and oil assets at each reporting date (every six months), starting with an analysis of any indicators of impairment. Where relevant this may involve the preparation of trigger test modelling, for certain CGUs, to determine if any indicators of impairment are present. Where indicators of impairment are present, the Group will test whether the CGU’s recoverable amount exceeds its carrying amount with reference to formal impairment models where discounted cash flow models are used to assess the recoverable amount. Relevant items of working capital and property, plant and equipment are allocated to CGUs when testing for impairment. The estimated expected cash flows used in the discounted cash flow model are based on management’s best estimate of the future production of reserves and sales volumes, commodity prices, foreign exchange rates, development expenditure in order to access the reserves, and operating expenditure. The Group’s commodity prices and foreign exchange rates for impairment testing are based on management’s best estimates of future market prices, with reference to external brokers, market data and futures prices. The Group’s gas price assumptions are based on contract prices applied against contracted gas volumes. The Group’s view of 109 COOPER ENERGY ANNUAL REPORT 2023Notes to the Consolidated Financial Statements For the year ended 30 June 2023 14. Impairment (continued) Significant accounting judgements, estimates and assumptions (continued) future uncontracted, long-term gas prices has been revised based on market data available, Southeast Australia gas market supply and demand information, oil prices and foreign exchange rates. The uncontracted pricing applies to a later time period as the Group has entered into a long-term gas sales agreement with AGL to supply gas from the Annie gas field The Group’s future pricing assumptions in FY23 dollar terms are set out below: Key assumption Brent crude oil (US$/bbl) FY2024 85.00 FY2025 85.00 FY2026 75.00 Uncontracted gas ($/GJ) 10.00 – 19.00 10.00 – 20.00 10.00 – 20.00 FY2027+ 75.00 12.00 The Group assumes foreign currency exchange rates of A$1/US$0.69 in all future periods. Discount rates applied in the net present value calculation of the FVLCD are derived from the weighted average cost of capital. The Group applied a pre-tax real discount rate of 9.6%. In the event circumstances vary from the assumptions used in the impairment assessment, the recoverable amount of the Group’s assets or CGUs could change materially and result in further impairment losses. The key variables that impact on asset values are often interrelated and therefore, changes in individual variables rarely occur in isolation of other changes. Furthermore, management is able to respond to certain changes in variables and mitigate losses or maximise value depending on the prevailing conditions that exist at the time. Accordingly, while sensitivities have been provided for specific changes in key assumptions, the indirect impact that a change in one variable has on another is impractical to estimate, as is the potential for, and size of any further impairment write-downs or reversals in future reporting periods. 110 COOPER ENERGY ANNUAL REPORT 2023Notes to the Consolidated Financial Statements For the year ended 30 June 2023 15. Provisions Current Liabilities Employee benefits Restoration provisions Non-Current Liabilities Employee benefits Restoration provisions Movement in carrying amount of the current restoration provision: Carrying amount at beginning of period Restoration expenditure incurred Changes in provisions¹ Transferred from non-current provisions Carrying amount at end of period Movement in carrying amount of the non-current restoration provision: Carrying amount at beginning of period Provisions acquired Changes in provisions¹ Transferred to current provisions Increase through accretion Restoration expenditure classified as held for sale Carrying amount at end of period 2023 $'000 2022 $'000 4,547 161,551 166,098 763 416,746 417,509 26,957 (25,720) 33,600 126,714 161,551 2,910 26,957 29,867 395 446,359 446,754 7,994 (3,095) - 22,058 26,957 446,359 355,652 78,887 1,474 (126,714) 16,740 - - 108,083 (22,058) 4,433 249 416,746 446,359 ¹Changes in provisions arise from a combination of changes to estimates of the cost to undertake restoration activities, changes to the estimated time periods during which restoration activity is forecast to occur, changes to assumed future rates of inflation to forecast future expected cost and changes to assumed discount rates to discount future expected costs to derive the present value included here within the restoration provision. Changes to estimates of the cost to undertake restoration activities arise from changes to the assumed scope of activity based on current planning for abandonment and remediation work, changes in the regulatory requirements and also arise from the current cost environment which, in some cases, have led to an increase to service costs. The discount rate used in the calculation of the provisions as at 30 June 2023 ranged from 3.49% to 5.65% (2022: 2.38% to 3.87%) reflecting a risk-free rate that aligns to the timing of restoration obligations. The movement in the risk-free rate reflects the change in Australian and US government bond rates since the last assessment. Inflation rate assumptions applied in the calculation of the provision as at 30 June 2023 ranged from 2.0% to 3.75 (2022: 2.0% to 4.5%). From 2009 until 2014, Pertamina Hulu Energi Australia Pty Limited (“Pertamina Australia”), a wholly owned subsidiary of PT Pertamina Hulu Energi (“Pertamina”), held a 10% interest in the BMG joint operating and production agreement (“JOA”). In October 2013, Pertamina Australia withdrew from the JOA. In December 2022, Cooper Energy filed a claim in the Supreme Court of Victoria against Pertamina, seeking payment of an amount equal to 10% of the costs and expenses of the abandonment operations incurred and to be incurred, pursuant to Pertamina Australia’s obligations under the withdrawal and abandonment provisions of the JOA. This has been incorporated into the judgements in the estimation of the BMG restoration provision. 111 COOPER ENERGY ANNUAL REPORT 2023Notes to the Consolidated Financial Statements For the year ended 30 June 2023 15. Provisions (continued) Accounting policy Provisions are recognised when the Group has a legal or constructive obligation, as a result of past transactions or other past events, and it is probable that a future sacrifice of economic benefits will be required and that a reliable estimate can be made of the amount of the obligation. producing life of the asset. Where it is not appropriate to recognise an asset, changes will go through profit or loss. Any change in assumptions is applied prospectively. These estimated costs are based on current technology available, State, Federal and International legislation and or industry practice. Employee benefits Liabilities for wages and salaries, including non-monetary benefits and annual leave are recognised in respect of employees’ services up to the reporting date and are measured at the amount expected to be paid when the liabilities are settled. Expenses for non-accumulating sick leave are recognised when the leave is taken and are measured at the rates paid or payable. The provision for long service leave is recognised and measured as the present value of expected future payments to be made in respect of services provided by employees up to the reporting date using the projected unit credit method. Consideration is given to expected future wage and salary levels, years of experience of departed employees, and periods of service. Expected future payments are discounted using market yields at the reporting date based on high quality corporate bonds with terms of maturity and currencies that match, as closely as possible, the estimated future cash outflows. Employees’ accumulated long service leave is ascribed to individual employees at the rates payable as and when they become entitled to long service leave. A provision for bonus is recognised and measured based upon the current wage and salary level and forms part of the employee short term incentive plan. The basis for the bonus relating to Key Management Personnel is set out in the Remuneration Report. Restoration The Group records a restoration provision for the present value of its share of the estimated cost to restore its sites. The nature of restoration activities includes the obligations relating to the reclamation, waste site closure, plant closure, production facility removal and other costs associated with the restoration of the site. Risks associated with climate change are factored into forecast timing of restoration activities and will continue to be monitored. A restoration provision is recognised upon commencement of construction and then reviewed every six months at each reporting date. When the liability is recorded, the carrying amount of the production or exploration asset is increased by the same amount and is depreciated over the remaining producing life of the asset. The movement is recorded as a restoration expense when there is no asset recorded. Over time, the liability is increased for the change in the present value based on a risk-free discount rate and the discount unwind is recorded as an accretion charge within finance costs. Any changes in the estimate of the provision for restoration arising from changes in the gross cost estimate or changes in the discount rate of the restoration provision are recorded by adjusting the provision and the carrying amount of the production or exploration asset, to the extent that it is appropriate to recognise an asset under accounting standards, and then depreciated over the remaining Significant accounting judgements, estimates and assumptions Provisions for restoration costs Decommissioning and restoration costs are a normal consequence of gas and oil extraction and the majority of this expenditure is incurred at the end of a field’s life, many years in the future. In determining an appropriate level of provision, assumptions are made as to the expected future costs to be incurred, the timing of these expected future costs (largely dependent on the life of the field), and the estimated future level of inflation. The ultimate cost of decommissioning and restoration is uncertain and these costs can vary in response to many factors. These factors include the extent of restoration required due to changes to the relevant legal or regulatory requirements, the emergence of new restoration techniques or experience at other fields, and prevailing service costs. The expected timing of expenditure can also change, for example in response to changes in gas and oil reserves or to production rates. Provisions for restoration costs are based on the Company’s best estimates based on the information available at the time. Changes to any of the estimates could result in significant changes to the amount of the provision recognised, which would in turn impact future financial results. The Group’s restoration provision includes the following costs: • • • for onshore projects, provision has been made for the demolition and removal of all onshore production facilities, removal of contaminated soil and revegetation of the affected area. Other plant and equipment restoration may include estimates for compensating landowners and the acquisition of land in line with the requirements of the relevant regulatory authority; for offshore assets, provision has been made for the removal of subsea trees and manifolds and removal of flowlines and umbilicals to a certain distance from shore and at a certain depth of water. This includes an assumption that all offshore materials that are constructed using plastics are to be fully removed; and offshore pipelines that are constructed from steel and concrete are assumed to remain in- situ, where it can be demonstrated that this will result in a net environmental benefit compared to full removal and where regulatory approval is anticipated to be obtained. Offshore pipelines that are constructed from steel and concrete have previously been accepted by the Australian regulator to be decommissioned in-situ where it has been demonstrated that this will result in a net environmental benefit compared to full removal. 112 COOPER ENERGY ANNUAL REPORT 2023Notes to the Consolidated Financial Statements For the year ended 30 June 2023 No assumption is made regarding the potential residual value for the onshore production facilities, nor regarding the potential to repurpose any of the onshore and offshore infrastructure and wells (e.g. potential to covert to gas storage and processing, or for carbon capture and storage). The Group estimates the future abandonment and restoration costs at different phases in an asset’s lifecycle, which in many instances occurs many years into the future. The provisions reflect the Group’s best estimate based on current knowledge and information, however further planning and technical analysis of the restoration activities for individual assets will be performed near the end of field life and/or when detailed decommissioning plans are required to be submitted to the relevant regulatory authorities. Actual abandonment and restoration costs can materially differ from the current estimate as a result of changes in regulations and their application, service costs, site conditions, timing of restoration and changes in removal technology. These uncertainties may result in abandonment and restoration costs differing from amounts included in the provision recognised as at 30 June 2023. In the event that the removal of all pipelines was required, the Group estimates the additional cost would lead to an increase to the provision of approximately $20.0 - $50.0 million. The Group’s provision in respect of the Sole Gas Project is based on estimated cessation of production of the fields and timing of abandonment activities is linked to NOPSEMA’s restoration guidance. It is intended that existing infrastructure at Sole will be utilised in a future Manta development. This would therefore extend the timing of these abandonment activities. 16. Leases The Group as a lessee The Group has lease contracts for properties with lease terms of between 1-11 years and fixed monthly payments. The Group also has certain leases with lease terms of 12 months or less and low value leases. Right-of-use assets Reconciliation of carrying amounts at beginning and end of period: Carrying amount at beginning of period Additions Depreciation Carrying amount at end of period Cost Accumulated depreciation Carrying amount at end of period Lease liabilities Reconciliation of carrying amounts at beginning and end of period: Carrying amount at beginning of period Additions Accretion of interest Payments Carrying amount at end of period Current Non-Current 2023 $'000 2022 $'000 7,520 1,047 (1,119) 7,448 11,905 (4,457) 7,448 10,863 1,047 495 (1,756) 10,649 1,467 9,182 8,625 - (1,105) 7,520 10,858 (3,338) 7,520 12,004 546 (1,687) 10,863 1,251 9,612 Short-term and low-value lease asset exemptions For the year ending 30 June 2023, the following expense has been recognised in the Statement of Comprehensive Income for lease arrangements that have been classified as short-term leases or low-value assets. Short-term leases Leases for low-value assets Total expense recognised The Group had total cash outflows for leases of $11.2 million (2022: $1.7 million), inclusive of leases for short-term leases and low-value assets. 9,238 176 9,414 - 91 91 113 COOPER ENERGY ANNUAL REPORT 2023Notes to the Consolidated Financial Statements For the year ended 30 June 2023 Accounting policy The Group recognises right-of-use assets and corresponding lease liabilities at the commencement date of the lease (the date the underlying asset is available for use). Right-of-use assets are initially measured as a value equal to the respective lease liability, adjusted for any initial direct costs incurred, and lease payments made at or before the commencement date, less any lease incentives received. Subsequently, right-of-use assets are measured at cost, less any accumulated depreciation and impairment losses, and adjusted for any remeasurement of lease liabilities. Property right-of-use assets are depreciated on a straight-line basis over the shorter of estimated useful life and the respective lease term. Right-of-use assets are also allocated to CGUs when testing for impairment (refer to Note 14). Lease liabilities are excluded from the carrying amount of a CGU. At the commencement date of the lease, the Group recognises lease liabilities measured as the present value of lease payments to be made over the lease term. In calculating the present value of lease payments, the Group uses the incremental borrowing rate at the lease commencement date if the interest rate implicit in the lease is not readily determinable. Subsequent to initial measurement, the amount of lease liabilities is increased to reflect the accretion of interest and reduced for the lease payments made. The carrying amount of lease liabilities is remeasured if there is a modification, a change in the lease term, a change in the fixed lease payments or a change in the assessment to purchase the underlying asset. The Group applies the short-term lease recognition exemption to its short-term leases (those leases that have a lease term of 12 months or less from the commencement date and do not contain a purchase option). It also applies the lease of low-value assets recognition exemption to leases of office equipment that are considered of low value (below $10,000). Lease payments on short-term leases and leases of low-value assets are recognised as an expense on a straight-line basis over the lease term. Significant accounting judgements, estimates and assumptions Lease term of contracts with renewal options The Group determines the lease term as the non- cancellable term of the lease, together with any periods covered by an option to extend the lease, if the option is reasonably certain to be exercised. The Group has the option, under some of its leases, to lease the assets for additional terms of three to five years. The Group applies judgement in evaluating whether it is reasonably certain to exercise the option to renew. The Group continues to reassess the lease over its term to determine if there is a significant event or change in circumstances that would impact the renewal decision. The Group has included the renewal period as part of the lease term for its property leases. 114 COOPER ENERGY ANNUAL REPORT 2023Notes to the Consolidated Financial Statements For the year ended 30 June 2023 Funding and Risk Management 17. Interest bearing loans and borrowings Current bank debt Non-current bank debt Net of capitalised transaction costs of $14.0 million (2022: $nil). 2023 $'000 - 143,956 2022 $'000 37,000 121,000 In July 2022, Cooper Energy executed a $400.0 million senior secured reserve based lending facility, secured across aportfolio of producing assets, together with a senior secured $20.0 million working capital facility. It is expected that the facility will be utilised to part fund the Company’s share of the BMG abandonment project and a portion of the planned OP3D growth project in the Otway Basin. Cooper Energy is in compliance with all covenants at 30 June 2023. A summary of the Group’s secured facilities is included below. Facility Currency Limit Senior secured reserve based lending facility Working Capital Facility Australian dollars Australian Dollars $400.0 million¹ (2022: $158.0 million) $20.0 million (2022: $15.0 million) Utilised amount $158.0 million (2022: $158.0 million) $7.7 million³ (2022: $7.1 million) Accounting balance $144.0 million (2022: $158.0 million) Nil (2022: Nil) Effective interest rate 9.30% floating Nil Maturity² 30 September 2027² 30 September 2024 ¹As at 30 June 2023, $242.0 million of the original facility limit of $400.0 million remains available. ²Based on the facility repayment schedule, the reserves profile of the borrowing base assets and the facility maturity date. ³As at 30 June 2023, no cash amounts have been drawn, $7.7 million has been utilised by way of bank guarantees. Accounting policy Borrowings are recognised initially at fair value net of directly attributable transaction costs. Subsequent to initial recognition, borrowings are stated at amortised cost, with any difference between cost and redemption value being recognised in profit or loss over the period of the borrowings on an effective interest basis. Transaction costs are capitalised initially and included in the effective interest rate calculation and unwound over the expected term of the facility. Borrowings are classified as current liabilities unless the Group has a right to defer the settlement of the liability for at least 12 months after the end of the reporting period. Interest expense is recognised as interest accrues using the effective interest rate and if not paid at balance date, is reflected in the balance sheet as a payable. 18. Net finance costs Finance Income Interest income Finance Costs Unwind discount on liabilities Finance costs associated with lease liabilities Interest expense Total finance costs Net finance costs Accounting policy 2023 $'000 2022 $'000 3,019 468 (17,974) (495) (11,027) (29,496) (26,477) (4,461) (546) (9,092) (14,099) (13,631) Interest earned is recognised in the Consolidated Statement of Comprehensive Income as finance income and is recognised as interest accrues using the effective interest rate. This is the rate that exactly discounts estimated future cash receipts through the expected life of the financial instrument to the net carrying amount of the financial asset. Interest expense is capitalised to the cost of a qualifying asset during the development phase. 115 COOPER ENERGY ANNUAL REPORT 2023Notes to the Consolidated Financial Statements For the year ended 30 June 2023 19. Contributed equity and reserves For the purposes of Group capital management, capital includes issued capital and all other equity reserves attributable to the equity holders of the parent entity. The primary objective of the Group’s capital management strategy is to maintain an appropriate capital profile to support its business activities and to maximise shareholder value. On 20 June 2022, the Company announced a fully underwritten $244 million equity offering, comprising a 2-for-5 accelerated, non-renounceable entitlement offer (“ANREO”) to raise a total of $160 million, together with a $84 million placement to institutional investors (the “2022 equity raising”). Share Capital Ordinary shares issued and fully paid At 30 June 2023, the Group has utilised $158.0 million of its reserves based lending facility. The Group manages its capital structure and makes adjustments in light of economic conditions and the requirements of the financial covenants. To maintain or adjust the capital structure, the Group may adjust its dividend policy, return capital to shareholders, issue new shares or draw on debt. No changes were made in the objectives, policies or processes during the current and prior period. 2023 $'000 2022 $'000 716,726 478,261 Thousands 2022 $'000 1,631,026 477,675 - - 1,708 - - 586 Movement in ordinary shares on issue At 1 July Equity issue¹ Transfer from reserves² Issuance of shares for performance rights and share appreciation rights Thousands 1,632,734 248,855 747,097 2,844 2023 $'000 478,261 58,596 179,508 361 At 30 June 2,631,530 716,726 1,632,734 478,261 ¹In July 2022, the group raised $58.6 million (net of $2.4 million after tax costs) via the retail portion of the ANREO, being the second component of the 2022 equity raising. The first component comprised the institutional portion of the ANREO plus an institutional placement, with the combined cash from this first component received in June 2022. The retail portion of the ANREO resulted in the issuance of 248.9 million shares on 14 July 2022. ²At the end of June 2022, the group raised $179.5 million (net of $3.5 million after tax costs) via the institutional portion of the ANREO plus an institutional placement, being the first component of the 2022 equity raising. The second component comprised the retail portion of the ANREO which completed in July. While the total cash from the combination of the institutional portion of the ANREO and the institutional placement was received at the end of June 2022, the resulting 747.1 million shares were issued on 1 July 2022. As a result, the institutional component of the 2022 equity raising was recorded within reserves at 30 June 2022 and subsequently transferred from reserves to equity in July 2022. Accounting policy Issued and paid up capital is recognised as the fair value of the consideration received by the Group. The shares issued do not have a par value and there is no limit on the authorised share capital of the Group. Fully paid ordinary shares carry one vote per share, which entitles the holder to participate in the proceeds on winding up of the Company in proportion to the number of, and amounts paid on, the shares held. Any transaction costs arising on the issue of ordinary shares that would not have been incurred had ordinary shares not been issued, are recognised directly in equity as a reduction of the share proceeds received. 116 COOPER ENERGY ANNUAL REPORT 2023Notes to the Consolidated Financial Statements For the year ended 30 June 2023 19. Contributed equity and reserves (continued) Cash raised from institutional portion of equity issue¹ 179,508 Reserves Consolidated At 30 June 2021 Other comprehensive income/ (expenditure) Transferred to retained earnings Transferred to issued capital Share-based payments At 30 June 2022 Other comprehensive income/ (expenditure) Transferred to issued capital Share-based payments At 30 June 2023 ¹See footnote 2 under the Share Capital table above. Share capital reserve $’000 Consol. Reserve $’000 Share based payment reserve $’000 Option premium reserve $’000 Equity instrument reserve $’000 Total $’000 - - - - - (541) 15,080 25 - - - - - - - - (586) 4,011 - - - - - 179,508 (541) 18,505 25 - (179,508) - - - - - - (361) 7,667 - - - (446) (332) 14,118 (332) - 179,508 906 - - 128 648 - - 906 (586) 4,011 197,625 648 (179,869) 7,667 (541) 25,811 25 776 26,071 Nature and purpose of reserves Consolidation reserve This reserve comprises the premium paid on acquisition of minority shareholdings in a controlled entity. Share based payment reserve This reserve is used to record the value of equity benefits provided to employees, contractors and executive directors as part of their remuneration. Option premium reserve This reserve is used to accumulate amounts received from the issue of options. The reserve can be used to pay dividends or issue bonus shares. 20. Financial risk management Share capital reserve This reserve is used to record receipts from equity issuance, where the shares have not been formally issued. This will be reclassified to share capital upon formal share issue. Equity instruments reserve This reserve is used to capture the fair value movement in the value of equity instruments designated at fair value through Other Comprehensive Income. Items in this reserve are never recycled through profit or loss. The Group’s principal financial instruments comprise cash and short-term deposits (Note 5), receivables (Note 6), payables (Note 9), borrowings (Note 17) and other financial assets and liabilities as disclosed in the below table. Other financial assets – Non-Current Equity instruments1 Escrow proceeds receivable 1 The equity instruments consist of one investment. The Group has not received dividends during the financial year. Other financial liabilities – Non-Current Success fee financial liability Movement in carrying amount of the success fee financial liability: Carrying amount at 1 July Accretion of success fee liability Fair value adjustment Carrying amount at 30 June 2023 $'000 1,131 - 1,131 2,853 2,853 3,285 110 (542) 2,853 2022 $'000 483 1 484 3,285 3,285 3,582 28 (325) 3,285 117 COOPER ENERGY ANNUAL REPORT 2023Notes to the Consolidated Financial Statements For the year ended 30 June 2023 20. Financial risk management (continued) Fair value hierarchy Fair value is the price that would be received to sell an asset or the price that would be paid to transfer a liability in an orderly transaction between market participants at the measurement date. All financial instruments for which fair value is recognised or disclosed are categorised within the fair value hierarchy, described as follows, and based on the lowest level input that is significant to the fair value measurement as a whole: Level 1 Quoted market prices in an active market (that are unadjusted) for identical assets or liabilities Level 2 Valuation techniques for which the lowest level input that is significant to the fair value measurement is directly or indirectly observable Level 3 Valuation techniques for which the lowest level input that is significant to the fair value measurement is unobservable For financial instruments that are recognised at fair value on a recurring basis, the Group determines whether transfers have occurred between levels in the hierarchy by re-assessing categorisation (based on the lowest level input that is significant to the fair value measurement as a whole) at the end of each reporting period. Set out below are the carrying amounts and fair values of financial instruments held by the Group: Reserves Financial assets Trade and other receivables Equity instruments Escrow proceeds receivable Financial liabilities Trade and other payables Success fee financial liability Interest bearing loans and borrowings Carrying amount Fair value Level 2023 $’000 2022 $’000 2023 $’000 2022 $’000 2 1 2 2 3 2 28,797 1,131 - 30,467 483 1 28,797 1,131 - 30,467 483 1 87,941 2,853 32,752 3,285 87,941 2,853 32,752 3,285 143,956 158,000 158,257 161,088 The following summarises the significant methods and assumptions used in estimating the fair values of financial instruments. Equity instruments Equity instruments are not held for trading and measured at fair value through other comprehensive income based on an irrevocable election made at inception on an instrument basis. They are initially recognised at fair value plus any directly attributable transaction costs. After initial recognition, investments are remeasured to fair value determined by reference to their quoted market price on a prescribed equity stock exchange at the reporting date. Hence they are a Level 1 fair value measurement. Changes in the fair value of equity investments are recognised as a separate component of equity and not recycled to profit and loss at any stage. Any dividends received are reflected in profit or loss. Escrow proceeds receivable During the 2018 financial year, the Group completed the sale of OGPP to APA Group. A portion of proceeds from the salewas held in escrow, to be released upon certain conditions being satisfied. Amounts held in escrow are measured at amortised cost in the Consolidated Statement of Financial Position. During the period, the funds were returned to the Group after financial close of the acquisition of the OGPP from APA Group in July 2022. Success fee financial liability The success fee liability is the fair value of the Group’s liability to pay a $5.0 million success fee upon the commencement of commercial production of hydrocarbons on the Group’s VIC/RL 13-15 assets, which includes the Manta gas field, acquired on 7 May 2014. The significant unobservable level 3 valuation inputs for the success fee financial liability include: a probability of 33% that no payment is made and a probability of 67% the payment is made in 2032 The discount rate used in the calculation of the liability as at 30 June 2023 equalled 4.03% (30 June 2022: 3.27%). The financial liability is measured at fair value through profit and loss and valued using a discounted cash flow model. The value is sensitive to changes in discount rate and probability of payment. Significant changes in any of the key unobservable inputs would result in significantly higher or lower fair value measurement. 118 COOPER ENERGY ANNUAL REPORT 2023Notes to the Consolidated Financial Statements For the year ended 30 June 2023 Risk Management The Group manages its exposure to key financial risks in accordance with its risk management policy with the objective to ensure that the financial risks inherent in gas and oil production and exploration activities are identified and then managed, or kept as low as reasonably practicable. The Group has a separate Risk & Sustainability Committee. The main financial risks that arise in the normal course of business for the Group’s financial instruments are foreign currency risk, commodity price risk, share price risk, credit risk, liquidity risk and interest rate risk. The Group uses different methods to measure and manage different types of risks to which it is exposed. These include monitoring exposure to foreign exchange risk and assessments of market forecasts for interest rates, foreign exchange rates and commodity prices. Liquidity risk is monitored through the development of future rolling cash flow forecasts. The Board’s policy is that no speculative trading in financial instruments be undertaken. The primary responsibility for the identification and control of financial risks rests with the Managing Director and the Chief Financial Officer, under the authority of the Board. The Board is apprised of these and other risks at Board meetings and agrees any policies that may be implemented to manage any of the risks identified below. Market risk Market risk is the risk that the fair value of future cash flows of a financial instrument will fluctuate because of changes in market prices. Market risk comprises four types of risk: foreign currency risk, commodity price risk, interest rate risk and share price risk. Financial instruments affected by market risk include deposits, trade receivables, trade payables, accrued liabilities and borrowings. The sensitivity analyses in the following sections relate to the position as at 30 June 2023 and 30 June 2022. The sensitivity analyses are intended to illustrate the sensitivity to changes in market variables on the Group’s financial instruments and show the impact on profit or loss and shareholders’ equity, where applicable. When calculating the sensitivity analyses, it is assumed that the sensitivity of the relevant profit before tax item and/or equity is the effect of the assumed changes in respective market risks, with all other variables held constant. The Group has transactional currency exposure arising from oil sales which are denominated in United States dollars, whilst the great majority of costs are denominated in Australian dollars, with some costs incurred in Great British pounds and United States dollars. Transaction exposures, where possible, are netted off across the Group to reduce volatility and provide a natural hedge. a) Foreign currency risk The Group may from time to time have cash denominated in United States (“US”) dollars. At 30 June 2023, the Group has no foreign exchange hedge programmes in place. The Group manages the purchase of foreign currency to meet expenditure requirements, which cannot be netted off against US dollar receivables. The financial instruments which are denominated in US dollars are as follows: Financial assets Cash Trade and other receivables 2023 $'000 2022 $'000 29,956 - 25,631 2,313 b) Commodity price risk Commodity price risk arises from the sale of oil denominated in US dollars. The Group has provisional sales at 30 June 2023 of $nil (2022: $2.3 million). From time to time, the Group will use oil price options to manage some of its oil price exposures. The Group is exposed to changes in Southeast Australian gas spot prices, with respect to gas production in excess of contracted volumes. Spot gas trades at year end were executed with reference to the prevailing intraday price marker, i.e., at known settlement prices on the day. c) Interest rate risk The Group has borrowings of $158.0 million at 30 June 2023 (2022: $158.0 million). Interest on borrowings is at variable rates (refer to Note 17). The Group has fixed rate term deposits that are not impacted by changes in the interest rate at the balance date. d) Share price risk Share price risk arises from the movement of share prices on a prescribed stock exchange. The Group has equity instruments measured at fair value through Other Comprehensive Income the fair value of which fluctuates as a result of movement in the share price. 119 COOPER ENERGY ANNUAL REPORT 2023Notes to the Consolidated Financial Statements For the year ended 30 June 2023 20. Financial risk management (continued) The following table summarises the sensitivity of financial instruments held at the year end, to the market risks above, with all other variables held constant. If the Australian dollar were 10% higher at the balance date If the Australian dollar were 10% lower at the balance date If the interest rates were 100 basis points higher at the balance date If the interest rates were 100 basis points lower at the balance date If the average Brent crude oil price were 10% higher at the balance date If the average Brent crude oil price were 10% lower at the balance date If the share price were 10% higher at the balance date If the share price were 10% lower at the balance date Credit risk Liquidity risk 2023 $'000 2022 $'000 Impact on after tax profit (2,723) 3,328 (1,580) 1,580 - - (2,540) 3,105 (1,580) 1,580 254 (252) Impact on reserve 113 (113) 48 (48) Credit risk arises from the financial assets of the Group which comprise cash and cash equivalents and trade and other receivables including hedge settlement receivables, escrow proceeds receivable (disclosed as other financial assets), and certain prepayments. The Group’s exposure to credit risk arises from potential default of the counterparty, with a maximum exposure equal to the carrying amount of these instruments. The Group trades only with recognised creditworthy third parties and has had no exposure to expected credit losses. The Group has a concentration of credit risk with trade receivables due from a small number of entities which have traded with the Group since 2003. Trade receivables are settled on 30 to 90 day terms. The Group has some exposure to credit loss from other receivables and an amount of $7.3 million calculated on lifetime expected credit loss has been recognised in respect of credit-impaired receivables. Cash and cash equivalents are held at two financial institutions that each have a Standard & Poor’s credit rating of AA- (stable). At 30 June 2023 Trade and other payables Lease liabilities Interest bearing loans and borrowings Success fee financial liability At 30 June 2022 Trade and other payables Lease liabilities Interest bearing loans and borrowings Success fee financial liability 120 Liquidity risk is the risk that the Group will not be able to meet its financial obligations as they fall due. The liquidity position of the Group is managed to ensure sufficient liquid funds are available to meet all financial commitments in a timely and cost-effective manner. The Managing Director and Chief Financial Officer review the liquidity position on a regular basis, including cash flow forecasts, to determine the forecast liquidity position and maintain appropriate liquidity levels. Any fluctuation of the interest rate either up or down will have only a very limited impact on the principal amount of the cash on term deposit at the banks. The Group does not invest in financial instruments that are traded on any secondary market. The table below summarises the maturity profile of the Group’s financial liabilities based on contractual undiscounted payments: Less than 3 months $’000 3 to 12 months $’000 1 to 5 years $’000 Greater than 5 years $’000 68,679 - 19,262 - Total $’000 87,941 12,263 495 3,022 - 1,428 9,066 - 9,284 1,056 197,286 - 209,374 - 5,000 6,056 5,000 314,578 72,196 10,494 225,832 32,752 - - - 433 1,308 8,763 2,302 12,149 32,671 128,079 - - 5,000 - - 32,752 12,806 172,899 5,000 45,334 33,979 141,842 2,302 223,457 COOPER ENERGY ANNUAL REPORT 2023Notes to the Consolidated Financial Statements For the year ended 30 June 2023 Group Structure 21. Interests in joint arrangements The Group has the following interests in joint arrangements involved in the exploration and/or production of oil and gas in Australia: Ownership Interest 2023 2022 Joint Arrangements in Australia in which Cooper Energy Limited is the Operator/manager VIC/L24 & 30 VIC/P44 Gas exploration and production Gas exploration Athena Processing Plant Gas processing services Joint Arrangements in Australia in which Cooper Energy Limited is not the Operator/manager PEL 494 PEP 168 PEP 171 PRL 32 PEL 680 Oil and gas exploration Oil and gas exploration Oil and gas exploration Oil and gas exploration Oil and gas exploration PRL 85-104¹ (Formerly PEL 92) Oil and gas exploration and production PEL 931,2 PRL 237² Oil and gas exploration and production Oil and gas exploration PRL 207-209 (Formerly PEL 100)² Oil and gas exploration PRL 183-190 (Formerly PEL 110)² Oil and gas exploration ¹Includes associated PPLs. 50% 50% 50% 30% 50% 75% 30% 30% 25% - - - - 50% 50% 50% 30% 50% 75% 30% 30% 25% 30% 20% 19.165% 20% ²The assets and liabilities associated with these joint arrangements are held for sale as at 30 June 2022. The transaction completed on 2 August 2022. Accounting policy The Group has interests in arrangements that are controlled jointly. 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. A joint arrangement is either a joint operation or a joint venture. The Group has several joint arrangements which are classified as 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. In relation to its interests in joint operations, the Group recognises its: • • • • Assets, including its share of any assets held jointly Liabilities, including its share of any liabilities incurred jointly Revenue from the sale of its share of the output arising from the joint operation Expenses, including its share of any expenses incurred jointly 121 COOPER ENERGY ANNUAL REPORT 2023Notes to the Consolidated Financial Statements For the year ended 30 June 2023 21. Interests in joint arrangements (continued) Significant accounting judgements, estimates and assumptions Joint arrangements Judgement is required to determine when the Group has joint control over an arrangement, which requires an assessment of the relevant activities and when the decisions in relation to those activities require unanimous consent. The Group has determined that the relevant activities for its joint arrangements are those relating to the operating and capital decisions of the arrangement, such as approval of the capital expenditure program for each year and appointing, remunerating and terminating the key management personnel or service providers of the joint arrangement. Where joint control does not exist, the relationship is not accounted for as a joint arrangement. The considerations made in determining joint control are similar to those necessary to determine control over subsidiaries. 22. Investments in controlled entities (a) Deed of Cross Guarantee Pursuant to ASIC Corporations (Wholly-owned Companies) Instrument 2016/785 dated 29 September 2016, relief has been granted to certain controlled entities of Cooper Energy Limited from the Corporations Act 2001 for preparation, audit and lodgement of financial reports, and directors’ reports. As a condition of the Class Order, Cooper Energy Limited, and the controlled entities subject to the Class Order, entered into a Deed of Cross Guarantee. The effect of the deed is that Cooper Energy Limited has guaranteed to pay any deficiency in the event Judgement is also required to classify a joint arrangement. Classifying the arrangement requires the Group to assess their rights and obligations arising from the arrangement. Specifically, the Group considers: • • the structure of the joint arrangement – whether it is structured through a separate vehicle; and when the arrangement is structured through a separate vehicle, the rights and obligations arising from the legal form of the separate vehicle, the terms of the contractual arrangement, and other facts and circumstances (when relevant). This assessment often requires significant judgement. A different conclusion on joint control and also whether the arrangement is a joint operation or a joint venture, may materially impact the accounting. of the winding up of any member of the Closed Group, and each member of the Closed Group has given a guarantee to pay any deficiency, in the event that Cooper Energy Limited or any other member of the Closed Group is wound up. (b) Schedule of controlled entities The Group’s consolidated financial statements include the financial statements of Cooper Energy Limited and the subsidiaries listed in the following table. Ownership Interest Name Somerton Energy Limited Essential Petroleum Exploration Pty Ltd Cooper Energy (Australia) Pty Ltd Cooper Energy (PBF) Pty Ltd Cooper Energy (PB Pipelines) Pty Ltd Cooper Energy (CH) Pty Ltd Cooper Energy (TC) Pty Ltd Cooper Energy (MF) Pty Ltd Cooper Energy (MGP) Pty Ltd Cooper Energy (IC) Pty Ltd Cooper Energy (HC) Pty Ltd Cooper Energy (EA) Pty Ltd Cooper Energy (Sole) Pty Ltd Cooper Energy (VO) Pty Ltd Cooper Energy (Marketing) Pty Ltd Country of incorporation Australia Note (a) Australia Australia Australia Australia Australia Australia Australia Australia Australia Australia Australia Australia Australia Australia (a) (a) (a) (a) (a) (a) (a) (a) (a) (a) (a) (a) (a) (a) 2023 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 2022 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 122 COOPER ENERGY ANNUAL REPORT 2023Notes to the Consolidated Financial Statements For the year ended 30 June 2023 Name Cooper Energy (BMG) Pty Ltd Cooper Energy (CB) Pty Ltd Cooper Energy (Finance) Pty Ltd Cooper Energy (AGP) Pty Ltd Cooper Energy (CS) Pty Ltd Cooper Energy (MS) Pty Ltd Country of incorporation Australia Australia Australia Australia Australia Australia Note (a) (a) (a) (a) (a)(b) (a)(b) Ownership Interest 2023 100% 100% 100% 100% 100% 100% 2022 100% 100% 100% 100% 100% 100% The parties that comprise the Closed Group are denoted by (a) and parties added to the Closed Group in 2023 are denoted by (b) Accounting policy Business combinations are accounted for using the acquisition method. The consideration for an acquisition is measured as the aggregate of the consideration transferred, measured at acquisition date fair value and the amount of any non-controlling interest in the acquiree. For each business combination, the Group elects whether it measures the non- controlling interest in the acquiree at fair value or at the proportionate share of the acquiree’s identifiable net assets. Acquisition costs incurred are expensed and included in administrative expenses. When the Group acquires a business, it assesses the financial assets and liabilities acquired for appropriate classification and designation per AASB 9 Financial Instruments (AASB 9) in accordance with the contractual terms, economic circumstances and pertinent conditions as at the acquisition date. If the business combination is achieved in stages, the acquisition date fair value of the acquirers previously held equity interest in the acquiree is remeasured to fair value at the acquisition date through profit or loss. Any contingent consideration to be transferred by the acquirer will be recognised at fair value at the acquisition date. Subsequent changes to the fair value of the contingent consideration that is deemed to be an asset or liability will be recognised in accordance with AASB 9 and measured at fair value through profit and loss. If the contingent consideration is classified as equity it will not be remeasured. Subsequent settlement is accounted for within equity. In instances where the contingent consideration does not fall within the scope of AASB 9, it is measured in accordance with the appropriate AASB. An asset or group of assets that do not meet the definition of a business are accounted for as asset acquisitions. Under this method, assets are initially recognised at cost based on their relative fair value at the date of acquisition. Under this method transaction costs are capitalised to the asset and not expensed. 23. Parent entity information Information relating to the parent entity, Cooper Energy Limited Current Assets Total Assets Current Liabilities Total Liabilities Issued capital Accumulated loss Share capital reserve Option premium reserve Share based payment reserve Total shareholders’ equity Loss of the parent entity Total comprehensive loss of the parent entity 2023 $'000 472,382 720,192 2022 $'000 576,522 793,012 186,501 223,784 48,322 209,296 716,726 (246,153) - 25 25,810 496,408 478,261 (92,583) 179,508 25 18,505 583,716 (153,570) (153,570) (30,927) (30,927) 123 COOPER ENERGY ANNUAL REPORT 2023Notes to the Consolidated Financial Statements For the year ended 30 June 2023 Other Information 24. Commitments for expenditure The Group has the following commitments for exploration expenditure not provided for in the financial statements and payable. Due within 1 year Due within 1-5 years Total 2023 $'000 32,263 478 32,741 2022 $'000 31,360 32,735 64,095 From time to time through the ordinary course of business, Cooper Energy enters into contractual arrangements that may give rise to negotiated outcomes. As at 30 June 2023 the parent entity has bank guarantees for $7.7 million (2022: $7.1 million), see also Note 17. These guarantees are in relation to credit support for gas purchases and guarantees on office leases. 25. Contingent liabilities Contingent liabilities arise in the ordinary course of business through commercial disputes or claims, including contractual or third-party claims. These contingent liabilities are possible obligations whose existence will only be confirmed by the occurrence or non-occurrence of uncertain future events. Because it is not probable that a future sacrifice of economic benefits will be required or the amount of the obligation cannot be measured with sufficient reliability, the Group has not provided for these amounts in the financial statements. 26. Share based payments The Company’s amended equity incentive plan (“EIP”) was approved by shareholders at the 2019 AGM. Performance rights and share appreciation rights were issued for no consideration under the EIP. Issued rights vest as shares in the parent entity, subject to performance hurdles being met. A performance right is the right to acquire one fully paid share in the Company provided a specified hurdle is met and share appreciation rights are rights to acquire shares in the Company to the value of the difference in the Company share price between the grant date and vesting date. Testing of the performance rights and share appreciation rights will occur at the end of the three year performance period. Rights granted prior to the 2020 financial year may be retested once, 12 months after the original three year test date. At the end of the three year measurement period, those rights that were tested and achieved will vest. The vesting test is determined from the absolute total shareholder return of Cooper Energy’s share price ranked against the absolute total shareholder returns of 12 peer companies listed on the Australian Securities Exchange. If Cooper Energy is ranked lower than the 50th percentile, no rights will vest. If Cooper Energy is ranked in the 50th percentile, 30% of the eligible rights will vest. If Cooper Energy is ranked greater than the 50th percentile, but less than the 90th percentile, the amount of eligible rights vested will be based on a pro rata calculation. If Cooper Energy is ranked in the 90th percentile or higher, 100% of the eligible rights will vest. Performance rights are also granted as part of deferred awards under the short-term incentive plan (“STIP”). Testing of these rights will occur at the end of a 12-month performance period. Rights granted will vest if the employee remains employed by the Company at the end of the performance period. There are no participating rights or entitlements inherent in the rights and holders will not be entitled to participate in new issues of capital offered to shareholders during the period of the rights. All rights are settled by physical delivery of shares. Information with respect to the number of performance rights and share appreciation rights granted to employees is as follows: Date Granted 11 December 2019 11 December 20191,2 10 December 2020 10 December 20202 9 December 2021 9 December 20212 9 December 2022 9 December 20222 Number of share appreciation rights (SARs) granted Number of performance rights granted Average share price at commencement date of grant Average contractual life of rights at grant date in years Remaining life of rights in years 14,871,802 4,257,209 - 769,605 20,473,191 6,394,202 - 1,885,834 28,449,812 9,043,984 - 3,159,165 20,636,373 7,608,195 - 8,641,505 $0.575 $0.575 $0.390 $0.390 $0.270 $0.270 $0.195 $0.195 3 1 3 1 3 1 3 1 - - 0.5 - 1.5 - 2.5 0.5 ¹Granted in December 2019 and exercised in December 2020. ²Relates to deferred STIP performance rights granted. 124 COOPER ENERGY ANNUAL REPORT 2023Notes to the Consolidated Financial Statements For the year ended 30 June 2023 The number of performance rights and share appreciation rights held by employees is as follows: Balance at beginning of year - granted - vested - expired and not exercised - forfeited Balance at end of year Achieved at end of year ¹Includes deferred STIP issued as performance rights. Number of Share Appreciation Rights Number of Performance Rights¹ 2023 2022 2023 2022 71,695,778 57,433,406 20,636,373 28,449,812 - - (25,781,761) (14,187,440) (5,742,766) - 60,807,624 71,695,778 - - 26,086,626 16,249,700 (2,844,324) (8,772,365) (2,024,845) 28,694,792 - 20,919,555 12,203,149 (1,708,495) (5,327,583) - 26,086,626 - The fair value of services received in return for the performance rights granted are measured by reference to the fair value of performance rights granted. The estimate of the fair value of the services received is measured based on the Black-Scholes methodology to produce a Monte-Carlo simulation model that allows for the incorporation of market-based performance hurdles that must be met before the shares vest to the holder. Fair value assumptions Fair value of share appreciation rights at measurement date Fair value of performance rights at measurement date 11 December 2020 10 December 2021 9 December 2022 10.9 cents 25.6 cents 8.3 cents 18.5 cents 6.4 cents 13.4 cents Share price Risk free interest rate Expected volatility Dividend yield 39.0 cents 27.0 cents 19.5 cents 0.11% 45% 0% 0.97% 48% 0% 3.02% 52% 0% Accounting policy The Group provides benefits to employees of the Group in the form of share-based payment transactions, whereby employees render services in exchange for rights over shares (“equity-settled transactions”). The cost of these equity-settled transactions with employees is measured by reference to the fair value at the date at which they are granted and are recorded as an expense, with a corresponding increase in reserves, on a straight-line basis over the vesting period of the related instrument. The fair value is determined using the Black-Scholes methodology to produce a Monte-Carlo simulation model that takes into account the exercise price, the vesting period, the vesting and performance criteria, the non-tradable nature of the performance right or share appreciation right, the share price at grant date, the expected volatility of the price of the underlying share, the expected dividend yield and the risk-free interest rate for the term of the vesting period. There are no non-market vesting conditions (e.g., profitability, or sales growth targets), and as such the estimation of the fair value of the performance rights and share appreciation rights granted is based solely on the results of the Black-Scholes based Monte-Carlo simulation model. The volatility assumption is based on the actual volatility of Cooper Energy’s daily closing share price over the three-year period to the valuation date. The cost of equity-settled transactions is recognised, together with a corresponding increase in equity, over the period in which the performance and/or service conditions are fulfilled, ending on the date on which the relevant employees become fully entitled to the award (the vesting period). The cumulative expense recognised for equity-settled transactions at each reporting date until vesting date reflects: • • the extent to which the vesting period has expired; and the Group’s best estimate of the number of equity instruments that will ultimately vest. No adjustment is made for the likelihood of market performance conditions being met as the effect of these conditions is included in the determination of fair value at grant date. The Consolidated Statement of Comprehensive Income charge or credit, for a period, represents the movement in cumulative expense recognised as at the beginning and end of that period. No expense is recognised for awards that do not ultimately vest, except for awards where vesting is only conditional upon a market condition. If the terms of an equity-settled award are modified, as a minimum an expense is recognised as if the terms had not been modified. In addition, an expense is recognised 125 COOPER ENERGY ANNUAL REPORT 2023Notes to the Consolidated Financial Statements For the year ended 30 June 2023 Significant accounting judgements, estimates and assumptions The Group measures the cost of equity-settled transactions with employees by reference to the fair value of the equity instruments at the date at which they are granted. The fair value is determined by an external valuation expert using the calculation criteria. Accounting policy (continued) for any modification that increases the total fair value of the share-based payment arrangement, or is otherwise beneficial to the employees as measured at the date of modification. If an equity-settled award is cancelled, it is treated as if it had vested on the date of cancellation, and any expense not yet recognised for the award is recognised immediately. However, if a new award is substituted for the cancelled award and designated as a replacement award on the date that it is granted, the cancelled and new award are treated as if they were a modification of the original award, as described in the previous paragraph. The dilutive effect, if any, of outstanding performance rights and share appreciation rights is reflected as additional share dilution in the computation of diluted earnings per share. 27. Related party disclosures 28. Remuneration of Auditors The Group has a related party relationship with its joint arrangements (Note 21), its subsidiaries (Note 22), and its key management personnel (disclosure below). The key management personnel’s remuneration included in General Administration (see Note 2) is as follows: 2023 $ 2022 $ Short-term benefits 5,829,184 6,509,385 Other long-term benefits 89,311 22,941 Post-employment benefits 303,572 277,601 Performance rights and share appreciation rights 2,193,542 1,950,770 Termination benefits 2,534,604 26,076 Total 10,950,213 8,786,773 The auditor of Cooper Energy Limited is Ernst & Young Audit services Amounts received or due and receivable by Ernst & Young Australia for: Audit of statutory report of Cooper Energy Limited Other services Services in relation to one off transactions 2023 $ 2022 $ 486,380 444,700 486,380 444,700 228,000 Taxation and other services 49,500 119,100 Total fees to Ernst & Young 535,880 791,800 49,500 347,100 In 2022, a portion of total fees paid to Ernst & Young was in relation to the acquisition of the OGPP. 29. Events after the reporting period There are no significant events subsequent to 30 June 2023 at the date of this report. 126 COOPER ENERGY ANNUAL REPORT 2023Directors’ Declaration In accordance with a resolution of the Directors of Cooper Energy Limited, I state that: In the opinion of the Directors: (a) the financial statements and notes of the consolidated entity are in accordance with the Corporations Act 2001, including: (i) giving a true and fair view of the consolidated entity’s financial position as at 30 June 2023 and of its performance for the year ended on that date; and (ii) complying with Australian Accounting Standards and the Corporations Regulations 2001; (b) the financial statements and notes also comply with International Financial Reporting Standards as disclosed in the Basis of Preparation; and (c) there are reasonable grounds to believe that the Company will be able to pay its debts as and when they become due and payable. This declaration has been made after receiving the declarations required to be made to the Directors in accordance with section 295A of the Corporations Act 2001 for the financial year ended 30 June 2023. In the opinion of the Directors, as at the date of this declaration, there are reasonable grounds to believe that the members of the closed group identified in Note 22 will be able to meet any obligations or liabilities to which they are, or may become subject, by virtue of the Deed of Cross Guarantee between the Company and those members of the Closed Group pursuant to ASIC Corporations (Wholly-owned Companies) Instrument 2016/785. Signed in accordance with a resolution of the Directors. Mr John C. Conde AO Chairman 29 August 2023 Ms Jane L. Norman Managing Director & CEO 127 COOPER ENERGY ANNUAL REPORT 2023 Independent auditor’s report to the members of Cooper Energy Limited Ernst & Young 121 King William Street Adelaide SA 5000 Australia GPO Box 1271 Adelaide SA 5001 Tel: +61 8 8417 1600 Fax: +61 8 8417 1775 ey.com/au Independent auditor’s report to the members of Cooper Energy Limited Report on the audit of the financial report Opinion We have audited the financial report of Cooper Energy Limited (the Company) and its subsidiaries (collectively the Group), which comprises the consolidated statement of financial position as at 30 June 2023, the consolidated statement of comprehensive income, consolidated statement of changes in equity and consolidated statement of cash flows for the year then ended, notes to the financial statements, including a summary of significant accounting policies, and the directors’ declaration. In our opinion, the accompanying financial report of the Group is in accordance with the Corporations Act 2001, including: a. Giving a true and fair view of the consolidated financial position of the Group as at 30 June 2023 and of its consolidated financial performance for the year ended on that date; and b. Complying with Australian Accounting Standards and the Corporations Regulations 2001. Basis for opinion We conducted our audit in accordance with Australian Auditing Standards. Our responsibilities under those standards are further described in the Auditor’s responsibilities for the audit of the financial report section of our report. We are independent of the Group in accordance with the auditor independence requirements of the Corporations Act 2001 and the ethical requirements of the Accounting Professional and Ethical Standards Board’s APES 110 Code of Ethics for Professional Accountants (including Independence Standards) (the Code) that are relevant to our audit of the financial report in Australia. We have also fulfilled our other ethical responsibilities in accordance with the Code. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion. Key audit matters Key audit matters are those matters that, in our professional judgment, were of most significance in our audit of the financial report of the current year. These matters were addressed in the context of our audit of the financial report as a whole, and in forming our opinion thereon, but we do not provide a separate opinion on these matters. For each matter below, our description of how our audit addressed the matter is provided in that context. We have fulfilled the responsibilities described in the Auditor’s responsibilities for the audit of the financial report section of our report, including in relation to these matters. Accordingly, our audit included the performance of procedures designed to respond to our assessment of the risks of material misstatement of the financial report. The results of our audit procedures, including the procedures performed to address the matters below, provide the basis for our audit opinion on the accompanying financial report. A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation 128 COOPER ENERGY ANNUAL REPORT 2023Page 2 1. Carrying value of gas and oil assets and exploration and evaluation assets Why significant How our audit addressed the key audit matter As at 30 June 2023 the Group identified impairment indicators in respect of a single cash generating unit (‘CGU’). Impairment testing was undertaken, which resulted in an impairment charge of $26 million being recognised, as disclosed in Note 14 of the financial report. Australian Accounting Standards require the Group to assess in respect of the reporting period, whether there is any indication that an asset may be impaired, or conversely whether reversal of a previously recognised impairment may be required. If any such indication exists, an entity shall estimate the recoverable amount of the asset or CGU. Assessing indicators of impairment We evaluated whether there had been significant changes to the external or internal factors considered by the Group, in assessing whether indicators of impairment or reversal of impairment existed. Those indicators included specific matters related to the Group, CGUs and industry as well as broader market-based indicators. Impairment testing of CGUs for which triggers were identified We assessed the composition of the forecast cash flows and the reasonableness of key inputs used to formulate recoverable amounts. Depending on the CGU, our audit procedures included: The assessments for indicators of impairment and reversals of impairment are judgmental and include assessing a range of external and internal factors. Where impairment indicators are identified, forecasting cash flows for the purpose of determining the recoverable amount of a CGU involves accounting estimates and judgements and is affected by expected future performance and market conditions. The key forecast assumptions, such as discount rates, foreign exchange rates, commodity prices and recoverable hydrocarbon reserves used in the Group’s impairment assessment are disclosed in Note 14. We considered the impairment testing of the Group’s CGUs and its exploration and evaluation assets, and the related disclosures in the financial report, to be a key audit matter. Reconciling future production profiles to the latest hydrocarbon reserves and resources estimates (discussed further below), current sanctioned development budgets, long-term asset plans and historical operations. Developing a reasonable range of forecast oil and gas prices, based upon external data. We compared this range to the Group’s forecast oil and gas price assumptions to challenge whether the Group’s assumptions were reasonable. In developing our ranges, we obtained a variety of reputable third- party forecasts, peer information and market data (which contemplate forecast oil and gas demand in a decarbonising global economy). Evaluating discount rates used by the Group for impairment tests (which contemplate costs of capital considerations in light of a decarbonising global economy). Evaluating the reasonableness of inflation rates, foreign exchange rates and carbon costs used by the Group for impairment tests. Understanding the operational performance of the CGUs relative to plan, comparing future operating and development expenditure within the impairment assessments to current sanctioned budgets, historical expenditures and future project plans and ensuring variations were in accordance with our expectations. Testing the mathematical accuracy of the Group’s discounted cash flow models. Future production profiles A key input to impairment assessments is the Group’s production forecast, which is closely related to the Group’s hydrocarbon reserves and resource estimates and development plans. Our audit procedures on the work of the Group’s internal and external experts included: Assessing the processes and controls associated with estimating reserves and resources. A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation 129 COOPER ENERGY ANNUAL REPORT 2023Page 3 Why significant How our audit addressed the key audit matter Reading reports provided by internal and external experts and assessing their scopes of work and findings. Assessing the qualifications, competence and objectivity of the Group’s internal and external experts involved in the estimation process. Understanding the reasons for reserve changes or the absence of reserves changes, for consistency with other information that we obtained throughout the audit. Impact of Sustainability and Climate Change Risks In undertaking our impairment audit procedures, we incorporated consideration of sustainability and climate change related risks by: Carrying out sensitivity analysis of recoverable amounts across a range of key inputs which have been formulated to incorporate uncertainty risk associated with climate change, such as the inclusion of premiums in discount rates and alternative price forecasts which contemplate varied climate change assumptions and scenarios. Reviewing the recoverable amount for the appropriate inclusion of carbon costs. Assessing the audit results of procedures carried out over restoration and rehabilitation obligations and their impact on impairment risk (refer to the ‘Accounting for Restoration Obligations’ Key Audit Matter below). Inquiring of management and reading the Group’s communication and publicly stated climate commitments regarding sustainability and climate- related risks where relevant and their impact on financial reporting. Assessing whether the ‘other information’ presented by the Group, including their publicly stated climate commitments present a current period impairment indicator for any CGUs at reporting date. Exploration and Evaluation Assets For exploration and evaluation assets, we assessed whether any impairment indicators, as set out in AASB 6: Exploration for and Evaluation of Mineral Resources, were present, and performed audit procedures in respect of the conclusions reached by management, including: Assessing whether the Group’s right to explore was current, which included obtaining and assessing supporting documentation such as licenses, permits and agreements. Assessing the Group’s intention to carry out significant ongoing exploration and evaluation activities in the relevant areas of interest and enquiring of senior management as to their intentions A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation 130 COOPER ENERGY ANNUAL REPORT 2023Why significant Page 4 How our audit addressed the key audit matter and the strategy of the Group as it relates to particular areas of interest. Assessing whether exploration and evaluation data or other information existed to indicate that the carrying value of capitalised exploration and evaluation assets was unlikely to be recovered through successful evaluation and development or sale. We also assessed the adequacy of the financial report Note disclosures regarding the assumptions, key estimates and judgments applied by the Group in relation to the carrying values of exploration and evaluation, and gas and oil assets. 2. Restoration obligations Why significant How our audit addressed the key audit matter At 30 June 2023, the Group has recognised provisions for restoration obligations relating to onshore and offshore assets of $578 million. As disclosed in Note 15, the calculation of restoration provisions is conducted by specialist engineers and requires judgemental assumptions to be made by the Group regarding removal date, compliance with environmental legislation and regulations, the extent of restoration activities required, the engineering methodology for estimating costs, future removal technologies in determining the removal costs and liability-specific discount rates to determine the present value of these cash flows. The judgements and estimates in respect of restoration provisions are based upon conditions existing at 30 June 2023, including key assumptions related to certain items remaining in-situ. Australian regulatory approval for these items remaining in-situ will only be sought towards the end of the respective asset’s field life and accordingly, at 30 June 2023, there is uncertainty whether the Australian regulator will approve plans for these items to be decommissioned in-situ. The significant assumptions and estimates outlined above are inherently subjective. Changes to these assumptions can lead to changes in the restoration provisions. Accordingly, the disclosures in the financial report provide information about the assumptions made in the calculation of the restoration provision and uncertainties at 30 June 2023, in arriving at the Group’s best estimate of the present value of future obligations. We consider the restoration provision calculation and the related disclosures in the financial report to be a key audit matter. We assessed the restoration obligation provisions prepared by the Group, evaluating the assumptions and methodologies used and the estimates made. Our audit procedures included the following: Evaluating the Group’s process for identifying its legal and regulatory obligations for restoration and decommissioning and testing the completeness of operating locations. Understanding and documenting the controls over the Group’s internal methodology for determining and approving gross cost estimates used to calculate the Group’s restoration provisions. In conjunction with our environmental specialists, assessing the reasonableness and completeness of restoration cost estimates based on the relevant current legal and regulatory requirements. Assessing the qualifications, competence and objectivity of the Group’s internal and external experts engaged to carry out the gross restoration cost estimations as a basis for our reliance on the output of their work. Comparing current year cost estimates to those of the prior year and explanations from management and both internal and external experts for observed changes. Comparing the timing of the future cash outflows against the anticipated end-of-field lives, cross- checking that these dates were consistent with the Group’s reserve estimates, impairment calculations and regulatory notices. Evaluating the appropriateness of the discount rates, inflation rates and foreign exchange rates A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation 131 COOPER ENERGY ANNUAL REPORT 2023Page 5 Why significant How our audit addressed the key audit matter used to calculate the present value of each of the provisions. Testing the mathematical accuracy of the restoration provision calculations. Impact of Sustainability and Climate Change Risks In undertaking our audit procedures for restoration, we incorporated consideration of sustainability and climate change related risks by: Understanding the regulatory framework in which each project operates to ensure compliance with the regulatory requirements of the various jurisdictions as they relate to restoration obligations. Evaluating the assumptions associated with the form and extent of abandonment activities, including conformity with regulation and industry practice, and the nature of the items expected to be left in-situ in abandonment activities. Reviewing litigation registers, correspondence with solicitors and regulators to confirm the completeness of liabilities recognised. Considering the estimated dates for the commencement of restoration and rehabilitation activities, possible impacts of physical risks of climate change and performing sensitivity analyses aligned with a range of scenarios associated with the Group’s net zero climate targets. We also assessed the adequacy of the financial report Note disclosure of the assumptions, key estimates and judgements applied by the Group. Information other than the financial report and auditor’s report thereon The directors are responsible for the other information. The other information comprises the information included in the Company’s 30 June 2023 Annual Report other than the financial report and our auditor’s report thereon. We obtained the directors’ report and the Overall Financial Review that are to be included in the annual report, prior to the date of this auditor’s report, and we expect to obtain the remaining sections of the annual report after the date of this auditor’s report. Our opinion on the financial report does not cover the other information and we do not and will not express any form of assurance conclusion thereon, with the exception of the Remuneration Report and our related assurance opinion. In connection with our audit of the financial report, our responsibility is to read the other information and, in doing so, consider whether the other information is materially inconsistent with the financial report or our knowledge obtained in the audit or otherwise appears to be materially misstated. If, based on the work we have performed on the other information obtained prior to the date of this auditor’s report, 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. A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation 132 COOPER ENERGY ANNUAL REPORT 2023Page 6 Responsibilities of the directors for the financial report The directors of the Company are responsible for the preparation of the financial report that gives a true and fair view in accordance with Australian Accounting Standards and the Corporations Act 2001 and for such internal control as the directors determine is necessary to enable the preparation of the financial report that gives a true and fair view and is free from material misstatement, whether due to fraud or error. In preparing the financial report, the directors are responsible for assessing the Group’s ability to continue as a going concern, disclosing, as applicable, matters relating to going concern and using the going concern basis of accounting unless the directors either intend to liquidate the Group or to cease operations, or have no realistic alternative but to do so. Auditor’s responsibilities for the audit of the financial report Our objectives are to obtain reasonable assurance about whether the financial report as a whole is free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with the Australian Auditing Standards will always detect a material misstatement when it exists. Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions of users taken on the basis of this financial report. As part of an audit in accordance with the Australian Auditing Standards, we exercise professional judgment and maintain professional scepticism throughout the audit. We also: Identify and assess the risks of material misstatement of the financial report, whether due to fraud or error, design and perform audit procedures responsive to those risks, and obtain audit evidence that is sufficient and appropriate to provide a basis for our opinion. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control. Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Group’s internal control. Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates and related disclosures made by the directors. Conclude on the appropriateness of the directors’ use of the going concern basis of accounting and, based on the audit evidence obtained, whether a material uncertainty exists related to events or conditions that may cast significant doubt on the Group’s ability to continue as a going concern. If we conclude that a material uncertainty exists, we are required to draw attention in our auditor’s report to the related disclosures in the financial report or, if such disclosures are inadequate, to modify our opinion. Our conclusions are based on the audit evidence obtained up to the date of our auditor’s report. However, future events or conditions may cause the Group to cease to continue as a going concern. Evaluate the overall presentation, structure and content of the financial report, including the disclosures, and whether the financial report represents the underlying transactions and events in a manner that achieves fair presentation. A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation 133 COOPER ENERGY ANNUAL REPORT 2023Page 7 Obtain sufficient appropriate audit evidence regarding the financial information of the entities or business activities within the Group to express an opinion on the financial report. We are responsible for the direction, supervision and performance of the Group audit. We remain solely responsible for our audit opinion. We communicate with the directors regarding, among other matters, the planned scope and timing of the audit and significant audit findings, including any significant deficiencies in internal control that we identify during our audit. We also provide the directors with a statement that we have complied with relevant ethical requirements regarding independence, and to communicate with them all relationships and other matters that may reasonably be thought to bear on our independence, and where applicable, actions taken to eliminate threats or safeguards applied. From the matters communicated to the directors, we determine those matters that were of most significance in the audit of the financial report of the current year and are therefore the key audit matters. We describe these matters in our auditor’s report unless law or regulation precludes public disclosure about the matter or when, in extremely rare circumstances, we determine that a matter should not be communicated in our report because the adverse consequences of doing so would reasonably be expected to outweigh the public interest benefits of such communication. Report on the audit of the Remuneration Report Opinion on the Remuneration Report We have audited the Remuneration Report included in pages 24 to 47 of the directors’ report for the year ended 30 June 2023. In our opinion, the Remuneration Report of Cooper Energy Limited for the year ended 30 June 2023, complies with section 300A of the Corporations Act 2001. Responsibilities The directors of the Company are responsible for the preparation and presentation of the Remuneration Report in accordance with section 300A of the Corporations Act 2001. Our responsibility is to express an opinion on the Remuneration Report, based on our audit conducted in accordance with Australian Auditing Standards. Ernst & Young D Hall Partner Adelaide 29 August 2023 A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation 134 COOPER ENERGY ANNUAL REPORT 2023Auditor’s Independence Declaration to the Directors of Cooper Energy Limited Ernst & Young 121 King William Street Adelaide SA 5000 Australia GPO Box 1271 Adelaide SA 5001 Tel: +61 8 8417 1600 Fax: +61 8 8417 1775 ey.com/au Auditor’s Independence Declaration to the Directors of Cooper Energy Limited As lead auditor for the audit of the financial report of Cooper Energy Limited for the financial year ended 30 June 2023, I declare 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; b. No contraventions of any applicable code of professional conduct in relation to the audit; and c. No non-audit services provided that contravene any applicable code of professional conduct in relation to the audit. This declaration is in respect of Cooper Energy Limited and the entities it controlled during the financial year. Ernst & Young D Hall Partner Adelaide 29 August 2023 A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation 135 COOPER ENERGY ANNUAL REPORT 2023Securities Exchange and Shareholder Information As at 31 August 2023 Listing Number of shareholders The company’s shares are quoted on the Australian Securities Exchange under the code of “COE”. There were 9,051 shareholders. All issued shares carry voting rights. On a show of hands every member at a meeting of shareholders shall have one vote and upon a poll each share shall have one vote. Distribution of shareholding (at 31 August 2023) Size of shareholding Number of holders Number of shares % of issued capital 1 - 1,000 1,001 - 5,000 5,001 - 10,000 10,001 - 100,000 100,000 Over Total Unquoted options on issue Nil Unquoted Performance Rights Number of holders of Performance Rights 75 13 Unmarketable parcels 1,000 2,182 1,387 3,485 997 257,014 6,233,347 11,258,934 130,485,296 2,483,296,669 0.01 0.24 0.43 4.96 94.37 9,051 2,631,531,260 100.00 Rights 28,694,792 Performance Rights 60,807,624 Share Appreciation Rights There were 2,775 members, representing 4,535,383 shares, holding less than a marketable parcel of 4,167 shares in the company. Twenty largest shareholders Rank Name Number of shares % of issued capital 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. Citicorp Nominees Pty Limited HSBC Custody Nominees (Australia) Limited - A/C 2 HSBC Custody Nominees Australia Limited JP Morgan Nominees Australia Pty Limited McCusker Holdings Pty Ltd HSBC Custody Nominees (Australia) Limited - GSI EDA National Nominees Limited BNP Paribas Nominees Pty Ltd BNP Paribas Noms Pty Ltd UBS Nominees Pty Ltd 585,783,004 435,234,894 332,447,620 305,958,951 60,000,000 55,919,534 52,761,951 50,141,441 41,980,197 38,853,218 HSBC Custody Nominees (Australia) Limited 15,193,337 Invia Custodian Pty Limited Zero Nominees Mr Leendert Hoeksema Invia Custodian Pty Limited GZ Family Holdings Pty Ltd Hooks Enterprises Pty Ltd 13,095,442 11,000,000 9,600,000 7,175,387 7,000,000 7,000,000 22.26 16.54 12.63 11.63 2.28 2.12 2.00 1.91 1.60 1.48 0.58 0.50 0.42 0.36 0.27 0.27 0.27 136 COOPER ENERGY ANNUAL REPORT 2023 18. 19. 20. Mr Simon Hannes + Mrs Mignon Catherine Booth Citicorp Nominees Pty Limited Good Dog Enterprises Pty Ltd 6,895,323 6,759,573 6,400,000 0.26 0.26 0.24 Substantial shareholders The following were substantial holders in the company, as disclosed in substantial holding notices given to the Company as required by section 671B of the Corporations Act. Name of entity L1 Capital Pty Limited Challenger Limited Mitsubishi UFJ Financial Perennial Value Management Limited Number of securities in which substantial shareholder has a relevant interest as at date of last notice Voting power as at date of last notice 451,183,158 244,946,190 244,475,047 136,092,120 17.15% 10.29% 9.29% 5.17% Enquiries and share registry address Investor information Shareholders with enquiries about their shareholdings should contact the Company’s share registry, Computershare Investor Services Pty Ltd, via the contact details in the Corporate Directory of this Annual Report. Online shareholder information Shareholders can obtain information about their holdings or view their account instructions online, as well as download forms to update their holder details. For identification and security purposes, you will need to know your Holder Identification Number (HIN/SRN), Surname/Company Name and Post/Country Code to access. This service is accessible via the Computershare website. Change of address Shareholders who have changed their address should advise Computershare in writing. Written notification can be mailed or faxed to Computershare and must include both old and new addresses and the security holder reference number (SRN) of the holding. Change of address forms are available for download from the Computershare website. Alternatively, holders can amend their details on-line via the Computershare website. Shareholders who have broker sponsored holdings should contact their broker to update these details. Information about the Company is available from a number of sources: Website: cooperenergy.com.au E-news: Shareholders can nominate to receive Company information electronically. This service is hosted by Computershare and can be accessed via Computershare’s website. Publications: The Annual Report is the major printed source of Company information. Other publications include the Sustainability Report, half-yearly and quarterly reports, company press releases and investor presentations. All publications can be obtained either through the Company’s website or by contacting the Company. Telephone or email enquiry: Morgan Wright, Investor Relations Lead, +61 8 8100 4982 morgan.wright@cooperenergy.com.au This Annual Report has been prepared to provide Shareholders with an overview of Cooper Energy Limited’s performance for the 2023 financial year and its outlook. The Annual Report is mailed to shareholders who elect to receive a copy and is available free of charge on request (see Shareholder Information printed in this Annual Report). This Annual Report and other information about the company can be accessed via the Company’s website at cooperenergy.com.au Annual Report mailing list Annual General Meeting Shareholders who wish to vary their annual report mailing arrangements should advise Computershare in writing. Electronic versions of the report are available to all via the Company’s website. Annual Reports will be mailed to all shareholders who have elected to be placed on the mailing list for this document. Annual Report election forms can be downloaded from the Computershare website. Forms for download All forms relating to amendment of holding details and holder instructions to the Company are available for download from the Computershare website. Date of meeting: Thursday, 9 November 2023 Time of meeting: 10:30 am (Australian Central Daylight Time) Place of meeting: Peppers Waymouth Hotel, 55 Waymouth Street, Adelaide SA 5000 The Notice of Meeting has been mailed to Shareholders. Additional copies can be obtained from the Company’s registered office or downloaded from the website at cooperenergy.com.au. COOPER ENERGY ANNUAL REPORT 2023 137 Abbreviations and Terms This Report uses terms and abbreviations relevant to the Group, its accounts and the petroleum industry. The terms “the Company” and “Cooper Energy” and “the Group” are used in the report to refer to Cooper Energy Limited and/or its subsidiaries. The terms “2023”, or “2023 financial year” refer to the 12 months ended 30 June 2023 unless otherwise stated. References to “2022”, or other years refer to the 12 months ended 30 June of that year. $: Australian dollars unless specified otherwise AASB: Australian Accounting Standards Board ACCC: Australia Competition and Consumer Commission LTIFR: lost time injury frequency rate: lost time injuries per million hours worked Mitsui: Mitsui E&P Australia and its associated entities AEMO: Australian Energy Market Operator AER: Australian Energy Regulator AGP: Athena gas plant ANREO: accelerated, non-renounceable entitlement offer Bass: Bass Oil Limited bbls: barrels of oil boe: barrels of oil equivalent CGU: cash generating unit EBITDAX: earnings before interest, tax, depreciation, amortisation, restoration, exploration and evaluation expense and impairment EIP: equity incentive plan FTE: full time equivalent MMbbl: million barrels of oil MMboe: million barrels of oil equivalent MTI: medical treatment injury NPAT: net profit after tax OGPP: Orbost gas processing plant OP3D: Otway phase three development Pertamina: PT Pertamina Hulu Energi PJ: petajoules PRRT: Petroleum resource rent tax STIP: short-term incentive plan TJ: terajoules TRCFR: total recordable case frequency rate. Recordable cases per million hours worked FVLCD: fair value less cost of disposal TRIFR: total recordable injury frequency rate The Gas Code: Mandatory Gas Code of Conduct TSA: transitional services agreement GSA: gas sales agreement GST: goods and services taxes US: United States VUI: value in use HSEC: health, safety, environment and community VWAP: volume weighted average price IFRS: International Financial Reporting Standards JV: joint venture JOA: joint operating agreement kbbl: thousand barrels of oil LNG: liquified natural gas LTI: lost time injury 2P: best estimate of reserves. The sum of proved plus probable reserves 2C: best estimate of contingent resources 138 COOPER ENERGY ANNUAL REPORT 2023 Corporate Directory Directors John C Conde AO, Chairman Jane L Norman, Managing Director & CEO Timothy G Bednall Victoria J Binns Giselle M Collins Elizabeth A Donaghey Jeffrey W Schneider Company Secretary Nicole Ortigosa Registered Office and Business Address Level 8, 70 Franklin Street Adelaide, South Australia 5000 Telephone: +618 8100 4900 Facsimile: +618 8100 4997 Email: customerservice@cooperenergy.com.au Website: www.cooperenergy.com.au Auditors Ernst & Young 121 King William Street Adelaide, South Australia 5000 Share Registry Computershare Investor Services Pty Limited Level 5,115 Grenfell Street Adelaide, South Australia 5000 Website: investorcentre.com/au Telephone: Australia: 1300 655 248 International: +61 3 9415 4887 Facsimile: +61 3 9473 2500 COOPER ENERGY ANNUAL REPORT 2023 139

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