Annual Report 2023 Delivering growth Beach Energy Limited ABN 20 007 617 969 Delivering growth Our Values Safety Safety takes precedence in everything we do Creativity We continuously explore innovative ways to create value Respect We respect each other, our communities and the environment Integrity We are honest with ourselves and others Performance We strive for excellence and deliver on our promises Teamwork We help and challenge each other to achieve our goals Cover image Kupe Gas Plant Inside Front Cover image Otway Gas Plant Beach Energy acknowledges the First Nations peoples of the lands on which we operate, live and gather and acknowledge their continuing connection to land, waters and community in Australia. We acknowledge the elders past and present for they hold the memories, traditions, culture and hopes of all First Nations peoples. We acknowledge iwi and hapū as tangata whenua of the land on which we operate in New Zealand and, in particular, acknowledge the relationship with Ngāti Manuhiakai hapū as kaitiaki who exercise mana whenua and mana moana within their takiwā. Our Vision We aim to be Australia’s premier multi-basin upstream oil and gas company Our Purpose Sustainably deliver energy for communities Contents About Beach Energy FY23 Highlights FY23 Strategic Pillars Markets Diverse Assets and Operations Sustainability Emissions Reduction From our Leadership Board of Directors Executive Team Operations Review Reserves Statement Directors' Report Auditor's Independence Declaration 2023 Remuneration in Brief (Unaudited) 2023 Remuneration Report (Audited) Directors' Declaration Financial Report Independent Auditor's Report Glossary Schedule of Tenements Shareholder Information Corporate Directory 02 03 04 05 06 08 10 12 16 18 20 34 38 53 54 55 71 72 116 122 124 127 128 About this Report This 2023 Annual Report is a summary of Beach’s operations, activities and financial position for the 12-month period ended 30 June 2023. In this report, unless otherwise stated, references to ‘Beach’ and the ‘Group’, the ‘company’, ‘we’, ‘us’ and ‘our’ refer to Beach Energy Limited and its subsidiaries. The Glossary defines terms used in this report. This report contains forward-looking statements. Please refer to page 46, which contains a notice in respect of these statements. All references to dollars, cents or $ in this document are to Australian currency, unless otherwise stated. Due to rounding, figures and ratios in tables and charts throughout this report may not reconcile to totals. An electronic version of this report is available on Beach’s website, www.beachenergy.com.au. The 2023 Corporate Governance Statement can be viewed on our website on the Corporate Governance page. Annual General Meeting Venue: Adelaide Convention Centre Address: North Terrace, Adelaide, South Australia 5000 Date: 14 November 2023 For more information, visit: www.beachenergy.com.au/agm 01 Production Beach Energy has a diverse portfolio of assets, spanning onshore and offshore operations across five hydrocarbon basins. 8% Perth Basin 11% Taranaki Basin 20% Western Flank and Other Cooper Basin 4% Bass Basin FY23 PRODUCTION FY23 PRODUCTION (MMboe) (MMboe) 19.5 23% Otway Basin 34% Cooper Basin JV About Beach Energy Beach Energy is an ASX‑listed oil and gas exploration and production company headquartered in Adelaide, South Australia. Beach’s purpose is to ‘sustainably deliver energy for communities’ and operates while maintaining high health, safety and environmental standards. Founded in 1961, Beach today produces oil and gas from five basins across Australia and New Zealand and is a key supplier to the Australian East Coast gas market. In addition to supplying the Australian and New Zealand domestic markets, Beach will enter the global LNG market when it commences export from the Waitsia field. Beach also has exploration permits across the onshore Cooper and Perth basins, onshore and offshore Otway Basin and offshore Taranaki Basin. Beach continues to pursue growth opportunities which align with our strategy, satisfy strict capital allocation criteria and demonstrate clear line of sight for sustainable shareholder value creation. Beach has a target of reducing equity emissions intensity from our portfolio by 35% by 2030 and we have an aspiration to reach Net Zero scope 1 and 2 emissions by 2050. Beach is a 33% stakeholder in the Moomba CCS project in the Cooper Basin, one of Australia’s largest emissions reduction projects. Beach is also assessing CCS opportunities in other basins and a range of alternative energy opportunities to complement our existing oil and gas portfolio, where it makes sense for our shareholders. Beach is committed to engaging positively with all of the local communities in which we operate. Beach provides local employment and supply chain opportunities and partners with a range of clubs and organisations. 02 Beach Energy Limited Annual Report 2023 FY23 Highlights Financial Performance Sales Revenue 2023 2022 2021 $1,617m $1,749m $1,519m Underlying EBITDA 2023 2022 2021 $982m $1,111m $953m Underlying NPAT 2023 2022 2021 $385m $504m $363m Operating cash flow 2023 2022 2021 $929m $1,223m $760m Dividends declared 2023 2022 2021 2.0 cps 2.0 cps 4.0 cps Financial & Commercial $434m available liquidity Environmental ~70% complete Moomba CCS progressed New dividend policy implemented LNG SPA executed with bp SA Premier's Energy & Mining Award: Environment No major spill events Operational 19.5 MMboe Produced in FY23 Safety 45% TRIFR down to 2.4 Thylacine North 1 and 2 connected APPEA Safety Project Excellence Award Waitsia Stage 2 progressed and Perth Basin exploration commenced Four operated sites recordable injury free 03 FY23 Strategic Pillars Our strategy is to support Australia’s energy security and build the foundation for sustainable growth. Optimise core producing assets >98% reliability All operated gas plants Western Flank horizontal oil drilling campaigns and horizontal fracture stimulation pilot program Accelerated Cooper Basin JV development drilling and optimisation activities Maintain financial strength $434m available liquidity New Capital Management Framework to fund growth and increase returns to shareholders Targeting net gearing of less than 15% Pursue other compatible growth opportunities Strengthen our complementary gas business Takeover pursued and ultimately withdrawn Ongoing assessment of inorganic growth opportunities Thylacine North 1 Thylacine North 2 Thylacine North 1 and 2 connected, Waitsia Stage 2 progressed and Perth Basin exploration commenced Rig secured and regulatory approvals received for Kupe South 9 development well Consortium rig secured for next phase of offshore Victoria activity Sustainability ~70% complete Moomba CCS progressed Several new energy opportunities at various stages of maturation Otway CCS pre-feasibility study complete 04 Beach Energy Limited Annual Report 2023 Markets Beach has exposure to five commodity markets with strong fundamentals. Global LNG + Global oil and liquids Global Executed SPA with bp to deliver up to 3.75 Mt of LNG Beach to be a new entrant in the global LNG market Geopolitical/energy security concerns highlight importance of LNG Limited investment in new supply accentuating imbalances Increasing demand outlook to support energy transition Unhedged exposure to Brent oil and liquids pricing East Coast gas Supplying ~12% of annual demand Significant investment in the Otway Basin to support the East Coast market Reducing coal-fired power, intermittent renewable supply and grid network instability support gas demand outlook Anticipate gas supply will continue to tighten Stable policy framework required to stimulate investment in new gas supply West Coast gas Supplying ~2% of annual demand Significant investment in development and exploration to support the domestic market Existing gas supply declining with tightness now emerging East Coast Darwin West Coast Adelaide Pipelines Brisbane Sydney Canberra Melbourne Hobart GD22-0085 New industries and demand opportunities emerging Perth New Zealand Pipelines New Zealand gas Supplying ~7% of annual gas demand and ~27% of annual LPG domestic supply Gas accounts for ~18% of energy mix and expected to remain a critical source Supply constraints emerging with no new gas developments Other major New Zealand gas fields in decline, supporting further investment in Kupe GD22-0085 Wellington Pipelines 05 GD22-0085 Diverse Assets and Operations Operating locations n i s a B h t r e P Perth Gas production Oil production Exploration/appraisal Processing facility Beach office n i s a B s s a B V J n i s a B r e p o o C Melbourne k n a l F n r e t s e W n i s a B r e p o o C ) A S ( n i s a B y a w t O Adelaide I ) C V ( n i s a B y a w t O Perth Basin Cooper Basin Western Flank Cooper Basin JV Otway Basin (SA) Otway Basin (VIC) Bass Basin Taranaki Basin Key Assets – Beharra Springs and Xyris gas plants – Middleton Gas Plant – Waitsia Gas Plant (under construction) – Beharra Springs and Waitsia gas fields – Oil infrastructure – ~30 producing oil and gas fields FY23 Highlights – Six-well Waitsia development drilling program completed – 16 horizontal oil development wells drilled – Moomba Gas Plant – ~200 producing oil and gas fields – Moomba CCS (under construction) – Participation in 117 wells with an overall success rate of 93% – Waitsia Gas Plant construction progressed – >5 years of recordable injury free at the Beharra Springs Gas Plant – Exploration drilling commenced 06 – Seven exploration and appraisal wells drilled with a success rate of 71% – Gas exploration success at the Coloy and Europa fields – Martlet facility capacity expansion complete – Moomba CCS ~70% complete – Haselgrove gas field – Otway Gas Plant – Lang Lang Gas Plant – Dombey gas field – Thylacine, Geographe, Enterprise, Speculant, – Yolla gas field – Kupe Gas Plant – Kupe gas field Halladale and Black Watch gas fields – Artisan and La Bella discoveries – Trefoil, White Ibis and Bass discoveries – Progressed analysis of – Safe completion of the seven-well offshore – Progressed interpretation of – Valaris 107 rig the Dombey 3D seismic drilling campaign the Prion 3D seismic survey – Katnook Gas Plant connected and Enterprise pipeline complete – Thylacine North 1 and 2 development wells – Progressed assessment of development options for existing discoveries and Yolla West contracted to drill the Kupe South 9 development well – Kupe Gas Plant reliability >99% – >2 years of recordable injury – No recordable free at the Lang Lang Gas Plant safety incidents – Consortium rig secured for next phase of offshore activity – >8 years of recordable injury free achieved at the Otway Gas Plant survey available for future exploration and development activity Beach Energy Limited Annual Report 2023 Community Investments Consulting and supporting communities in which we operate In FY23, Beach engaged with ~1,500 community members and ~1,000 local community groups and organisations to answer questions, listen to ideas and develop initiatives, while building long-term relationships. Beach’s community investment program supports initiatives that support sustainable and resilient communities and contributed $1.7 million that benefited over 9,000 people in FY23. n i s a B i k a n a r a T Celebrating 21 years supporting the Royal Flying Doctor Service In 2023, Beach is recognising 21 years of support for the Royal Flying Doctor Service (RFDS), which provides a critical emergency health response service to thousands of Australians each year, including the remote Cooper Basin area where Beach operates. The RFDS is one of the largest and most comprehensive aeromedical organisations in the world, providing extensive primary health care and 24-hour emergency services to people in regional and remote communities over an area of 7.7 million square kilometres. Beach employees are passionate about our partnership with RFDS, with the Cooper Basin operations team annually raising thousands of dollars through recycling of scrap metal, in addition to Beach’s annual corporate partnership. New Plymouth Perth Basin Cooper Basin Western Flank Cooper Basin JV Otway Basin (SA) Otway Basin (VIC) Bass Basin Taranaki Basin Key Assets – Beharra Springs and Xyris gas plants – Middleton Gas Plant – Waitsia Gas Plant (under construction) – Beharra Springs and Waitsia gas fields – Oil infrastructure – ~30 producing oil and gas fields – Moomba Gas Plant – ~200 producing oil and gas fields – Moomba CCS (under construction) FY23 Highlights – Six-well Waitsia development – 16 horizontal oil development – Participation in 117 wells drilling program completed wells drilled with an overall success rate – Waitsia Gas Plant construction progressed – >5 years of recordable injury free at – Seven exploration and of 93% appraisal wells drilled with a – Gas exploration success at success rate of 71% the Coloy and Europa fields the Beharra Springs Gas Plant – Martlet facility capacity – Moomba CCS ~70% complete – Exploration drilling commenced expansion complete – Haselgrove gas field – Otway Gas Plant – Lang Lang Gas Plant – Dombey gas field – Thylacine, Geographe, Enterprise, Speculant, – Yolla gas field – Kupe Gas Plant – Kupe gas field Halladale and Black Watch gas fields – Artisan and La Bella discoveries – Trefoil, White Ibis and Bass discoveries – Progressed analysis of – Safe completion of the seven-well offshore the Dombey 3D seismic survey – Katnook Gas Plant available for future exploration and development activity drilling campaign – Thylacine North 1 and 2 development wells connected and Enterprise pipeline complete – Consortium rig secured for next phase of offshore activity – >8 years of recordable injury free achieved at the Otway Gas Plant – Progressed interpretation of the Prion 3D seismic survey – Progressed assessment of development options for existing discoveries and Yolla West – >2 years of recordable injury free at the Lang Lang Gas Plant – Valaris 107 rig contracted to drill the Kupe South 9 development well – Kupe Gas Plant reliability >99% – No recordable safety incidents 07 Sustainability at Beach Energy for a sustainable transition Sustainability Report: Material topics The natural gas that Beach produces each day continues to be essential to our society. It is used to warm homes, cook food, and keep businesses running. Beach delivers an affordable, secure energy supply with our products today, as we explore future energy opportunities for our customers. We recognise that it is a time of significant change for the energy industry and that there are both challenges and opportunities that are ahead. We also recognise that the energy transition will take place over several decades and will involve substantial changes to the way energy is produced, stored, distributed and used. These changes need to be carefully managed to ensure energy is reliably supplied to meet society’s needs during the transition, whilst maintaining affordability. Natural gas will continue to be critical to ongoing economic prosperity as lower emissions technologies are developed and integrated into energy supply systems. Gas peaking electricity generation underpins the reliability of the electricity supply system as renewable energy replaces higher emitting electricity generation. Sustainability Report Consistent with our Sustainability Policy, Beach must assess and address material sustainability risks. Material topics are those where we prioritise our efforts to make a material change to our sustainability performance. The 2023 review of material topics used an evidence-based methodology based on known sustainability frameworks and considers internal and external factors, incorporating feedback from external stakeholders such as investors, regulators and community members. Our material topics, for which we have set FY24 targets in our Sustainability Report, are: – Diversity, equity and inclusion – Health and safety – Community engagement and investment – Indigenous participation – Greenhouse gas emissions – Climate adaptation, resilience and transition Visit the Beach Energy website to read the 2023 Sustainability Report. www.beachenergy.com.au/sustainability FY23 Highlights Emissions abatement >18,000 tCO2e from projects implemented in FY23 Safety 2.4 TRIFR down 45% on FY22, representing the second best performance on record Community investments $1.7m supporting 55 organisations Volunteering in Australia and New Zealand >55% increase on FY22 to 1,513 hours APPEA Safety Project Excellence Award COVID and mental health management SA Premier Resources Award (Environment) Dombey 3D Seismic Survey 08 Beach Energy Limited Annual Report 2023 Case Study Re‑establishing Coastal Wetlands In 2023, Beach staff participated in the first citizen science day for our three‑year flagship partnership with Blue Carbon Lab (BCL) in Victoria. The project is looking at restoring degraded mangrove systems in Western Port Victoria, trialling world first biodegradable lattice structures in the support of mangrove growth through to establishment, which is largely unsuccessful naturally due to such dynamic tidal activity. Beach employees collaborated with BCL staff and First Nations peoples to measure how well seedlings are growing in the lattice structures, seedling maturity and how much supporting sediment had built up to encourage seedling establishment. This project not only supports sustainability and environmental outcomes but also significantly contributes to communities by helping to enhance biodiversity e.g., sustain migratory birds, support fisheries and livelihoods, provide ecotourism and general tourism revenues and protect our coasts against erosion and extreme weather conditions. Case Study Strong agenda for volunteering Beach recognises the positive impact that volunteering can have for our people and the communities in which we operate. We know that volunteering plays a fundamental role in supporting the important activities of charitable organisations in contributing to more sustainable, healthy and resilient communities. When people volunteer, they feel good about giving back to the community and have an increased awareness of social and environmental issues. It has the added benefit of reconnecting people and building team camaraderie. Almost 30% of Beach employees took part in the Workplace Volunteering Program across Australia and New Zealand in FY23. Volunteering participation involved 166 individuals, across 15 events, with over 1500 volunteering hours. This included time volunteered at organisations including Bush for Life, Backpack 4 SA Kids, Treasure Boxes, Royal Flying Doctor Service, Habitat for Humanity, Cleland Wildlife Park, Clean Up Australia, Foodbank, Puddle Jumpers and the One and All. “Gas will continue to be critical to ongoing economic prosperity as lower emissions technologies are developed and integrated into energy supply systems.” 09 Emissions reduction trajectory to 2030 Beach remains confident it will achieve its equity emissions reduction target – to reduce scope 1 and 2 emissions intensity by 35% by 2030. As an equity emissions target, this accounts for emissions from operations according to our share of equity in the operation. This recognises emissions reduction progress across both operated and non-operated assets. Beach has continued work on reducing our operated emissions. In FY23, we delivered projects that, on an annualised basis, are forecast to exceed our FY23 target of 18,000 tCO2e. To achieve our 2030 equity emissions reduction target, Beach is pursuing a range of abatement opportunities. New Energy Opportunities TCFD alignment The Task-force on Climate Related Financial Disclosures (TCFD) reporting standard requires that certain information be shared in the four key areas of governance, strategy, risk management and metrics and targets. In FY23 we completed a review of our practices and aligned our approach with TCFD. Some of our key achievements include: Conducted a climate risk assessment, testing the financial and physical resilience of our existing portfolio of producing assets using scenario-based analysis. Refreshed the Climate Change and Sustainability policies. Updated capital allocation practices. Beach is currently assessing a number of opportunities to participate in renewable and emerging energy markets near existing operations and where value can be created for Beach’s stakeholders. These opportunities are at different stages of investigation and development and include: Offshore wind in the Gippsland Basin: Beach is a partner in a joint bid with Belgium’s Parkwind as part of the Commonwealth Government’s process for granting Offshore Electricity Infrastructure Feasibility Licences for potential offshore wind projects off the coast of Gippsland Victoria. Licenses are expected to be awarded later in 2023. Offshore/onshore wind energy opportunities in the Taranaki Basin: Beach’s current assets and infrastructure may provide a competitive advantage in what is already a key wind energy region for New Zealand. Hydrogen production and storage in South Australia and Victoria: Beach has conducted early stage pre-feasibility studies considering the potential options for direct supply of hydrogen to the local industry, transport sector, and/or blending into sales gas supply. 10 Beach Energy Limited Annual Report 2023 Moomba Carbon Capture and Storage Beach has a 33% ownership interest in the Moomba CCS project, operated by our joint venture partner Santos. Constructed adjacent to the Moomba Gas Plant in the Cooper Basin, the project is one of the world’s largest CCS projects and will deliver a material greenhouse gas reduction for Australia and Beach’s portfolio. Upon its completion, Moomba CCS will safely store up to 1.7 Mt per year of carbon emissions in the depleted reservoirs near the Moomba Gas Plant. First injection of CO2 from the project is scheduled in 2024, with ~70% of works complete, as reported by the operator, Santos. The Cooper and Eromanga basins in South Australia and Queensland have the potential for injection of over 20 Mt of CO2 per year for more than 50 years. “Carbon capture and storage is considered to have an important potential contribution to limiting the pace and extent of climate change.” — Commonwealth Government review of Australian Carbon Credit Units scheme December 2022 Moomba CCS construction CO2 per annum safely stored upon completion up to 1.7 Mt (gross) Capture C02 C02 transmission pipeline MOOMBA GAS PLANT Dehydrate Compress Injection wells Inject 11 Letter from the Chairman The past year marked a pivotal juncture as your company embarked on delivering the catalysts for growth, with new gas supply coming from Beach's recent offshore campaign. 12 Key highlights New Capital Management Framework and dividend policy SPA signed with bp for all of Beach's Waitsia Stage 2 LNG volumes Delivered new gas connections into the Australian East Coast domestic market Supporting the transition while delivering energy security Targeting 35% emissions intensity reduction by 2030 Moomba CCS first CO2 injection in 2024 targeted Net Zero by 2050 aspiration Scope 1 and 2 emissions Beach Energy Limited Annual Report 2023 Dear Shareholder, On behalf of the Beach Energy Board of Directors, I present the Annual Report for 2023. The oil and gas produced by Beach remains indispensable, powering societies across Australia and New Zealand. As western economies witness the gradual phasing out of coal from the energy mix, the reliance on Beach’s products is unwavering, and the significance of our Purpose – to ‘sustainably deliver energy for communities’ – has never been more pronounced. Our goal to provide critical energy products to our customers gains paramount importance amid these dynamics. The past year marked a pivotal juncture as your company delivered key milestones which underpin our growth ambitions. Connection of two offshore Otway Basin gas wells, progress on the Waitsia Stage 2 project and the start of gas exploration in the Perth Basin are prime examples. It was a year of progressing major growth projects, and as such the dip in production and financial performance we recorded was not unexpected. However, it is crucial to underscore that our fundamentals continue to strengthen. We are forging ahead and growing our presence in increasingly attractive markets. In recognition of progress made, Beach unveiled its Capital Management Framework this year. The framework provides a transparent approach for balancing ongoing investment in growth with dividends linked to free cash flow generation. It is our basis for delivering growth and increasing returns to shareholders while maintaining a robust financial position. The Capital Management Framework was implemented this year and the Board was pleased to declare a 100% increase in dividends for 2023 compared with the previous year. This in part reflects our confidence in Beach’s outlook. Our path to production and cash flow growth is now clearer than ever. On the West Coast of Australia, we are focused on completing the eagerly anticipated Waitsia Stage 2 project and selling our gas into the global LNG market. Despite financial challenges faced by our construction contractor during the year, the Waitsia Joint Venture continues to drive the project to first gas as soon as reasonably possible. On the East Coast of Australia, upcoming connections of the Enterprise discovery and the final two Thylacine development wells will help to extend the Otway Gas Plant’s production performance as we become an increasingly significant supplier of gas to the domestic market. In New Zealand, we await the imminent spudding of the Kupe South 9 development well, having secured final regulatory approvals and contracted the drilling rig during 2023. While in the Cooper Basin, we continue active oil and gas exploration, appraisal and development activity as we look to extend the life of these valuable assets. Kupe Gas Plant While gas plays a crucial role in the transition to a decarbonised energy system, we must also remain focused on reducing emissions from our operations. To that end, the Santos-operated Moomba Carbon Capture and Storage Project is a nation-leading emissions reduction project, that will make a material impact on Beach’s portfolio emissions once fully operational. Beach also continues to assess further clean energy opportunities where it makes sense for us to do so. Beach has recently confirmed a change in our leadership with current Santos VP Brett Woods to join the Company as Managing Director and Chief Executive Officer in February, with Director Bruce Clement as Interim CEO until that time. Brett is an experienced oil and gas executive with a track record in strong leadership, delivering operational excellence, project delivery and value creation for shareholders. He is a very experienced technical oil and gas leader with the skills and background to continue to strengthen our performance culture and operational delivery. On behalf of the Board of Directors, I’d also like to thank outgoing CEO Morné Engelbrecht for his service to Beach over the last seven years. Morné excelled in his role as CFO and stepped into the CEO position at an uncertain time and has since guided the company through a number of operational challenges. I wholeheartedly extend my gratitude to the remarkable team at Beach for their unwavering dedication and hard work throughout the year, enabling the accomplishments achieved this year. Lastly, I express my appreciation to you, our shareholders, for your continued support of Beach Energy. Regards, Glenn Davis Chairman 14 August 2023 13 Letter from the Interim CEO Dear Shareholder, Our Company has moved forward positively over the past year to be well positioned with a sound financial base and a number of growth projects planned for delivery over the coming year. Whilst there have been some challenges during the year, there is much to be excited about at Beach and reason to be confident in our future. We will soon be drilling in the Taranaki Basin in New Zealand and embarking on a new oil exploration and appraisal campaign in the Cooper Basin. The planned completion of the Waitsia Stage 2 project in 2024 will be a significant milestone for the company, while also in the Perth Basin, our gas exploration campaign will continue over the coming 12 months. We are also in the early planning stages for the Offshore Gas Victoria project which aims to extend production at the Otway Gas Plant. Lastly, the Moomba CCS project is also nearing completion and will deliver a significant reduction in Beach’s emissions. Importantly, Beach has been taking significant steps in recent years to deliver more domestic gas for both Australia and New Zealand to support the energy transition. In particular, the completion of our Offshore Otway drilling program and connection of new gas from the Thylacine field into the East Coast market ensured that more gas was available during the months of tight winter supply. A market where these additional supplies are critical. Speaking personally, the highlight for me this year was Beach’s improved safety performance. There is nothing more important in our business than ensuring our people go home from work injury-free. I want to thank the whole team for their unrelenting focus on safety throughout FY23, which we aim to continue in FY24. 14 FY23 financial review Beach ends the year in a strong financial position, with $434 million available liquidity and net gearing of 4%. In a year of major project delivery, an 11% decline in production to 19.5 MMboe was within our revised guidance range. A production uptick in the last quarter was achieved following connection of the Thylacine North development wells and clearing of the backlog of drilled but unconnected Western Flank oil wells. Sales revenue was down 8% to $1.6 billion due mainly to lower production and sales volumes. Underlying EBITDA of $1.0 billion was 12% below the prior year. Investment in our major growth projects continued with capital expenditure of $1.1 billion incurred. This year Beach announced a new Capital Management Framework to guide how we will balance growth and capital returns to shareholders. Implementation of the framework resulted in full year franked dividends declared of 4 cents per share, a 100% increase from the prior year. The framework provides a transparent pathway for increased shareholder returns while we prepare for and invest in our next stage of growth. FY23 operating review Beach recorded its second best-ever safety performance in FY23, achieving a Total Recordable Injury Frequency Rate of 2.4. This represents a 45% improvement compared with FY22. Four-out-of-the five operational sites completed the year recordable injury-free. This is an outstanding achievement. Beach also achieved several significant milestones across our major growth projects, particularly in the Otway and Perth basins. In the Otway Basin, completion of the offshore drilling campaign in 2022 paved the way for the connection of two Thylacine North development wells to the Otway Gas Plant in April 2023. As a result, well deliverability for the plant increased by ~70 TJ/day to ~170 TJ/day in time for the winter months. This is being delivered into an East Coast market where the where the additional gas volumes are critical. We also completed construction and installation of the Enterprise pipeline. First gas in the second half of FY24 is targeted, subject to approvals. Enterprise will further increase well deliverability for the Otway Gas Plant and is another new source of gas supply for the East Coast market. In the Perth Basin, the Waitsia Stage 2 project encountered a setback when our construction contractor, Clough, entered voluntary administration in December 2022. The Waitsia Joint Venture worked together to deliver a positive turnaround with Webuild now completing the project. These efforts led by the JV have seen activity on site ramp up significantly, and the project is very much full-steam-ahead towards an expected completion in 2024. Waitsia Stage 2 remains transformational for Beach, as it marks our entry into the global LNG market during a period of tightening supply conditions. Beach Energy Limited Annual Report 2023 While still in the Perth Basin, our exciting gas exploration campaign is underway and has already yielded success with the Gynatrix discovery. This campaign will continue throughout FY24, and we look forward to reporting outcomes during the year. In our Cooper Basin Western Flank operations, there was a focus on horizontal oil development drilling. The program consisted of 24 wells, 16 of which were horizontal wells with almost 20 kilometres of lateral section drilled. The campaign delivered encouraging results, several follow-up opportunities, and an uptick in production towards the end of the year. These results were achieved despite significant weather-related delays throughout the year. In FY24, our drilling campaign will be focused on more exploration and appraisal as we look to build inventory for future activity. The Cooper Basin JV operations also encountered weather-related challenges during the year which impacted production and costs. However, drilling outcomes were pleasing, with a success rate of 93% achieved from 117 wells drilled. In New Zealand, the team made great progress in securing regulatory approvals and a drilling rig for the Kupe South 9 development well which is planned to spud later in 2023. It was also another year of outstanding operational performance, with the Kupe Gas Plant achieving reliability of over 99%. Climate action The role of gas to enable the clean energy transition globally has never been more profound. As coal-fired energy generation retires in Australia over the coming decade, the reliance on gas during periods of peak demand is set to double over the next twenty years. It is evident that the success of transitioning to renewable energy hinges on the continued production of gas, which lies at the core of Beach's business. Our focus is on the decarbonisation of our existing portfolio, spearheaded by the Moomba CCS project, operated by Santos, which is scheduled for first CO2 injection in 2024. Once operational, it will have the capacity to store up to 1.7 million tonnes of CO2 annually, making a substantial contribution to mitigating greenhouse gas emissions. We are also actively evaluating the potential of implementing CCS in the Victorian Otway Basin, with the potential to eliminate our produced Scope 1 and 2 emissions at the Otway Gas Plant. Through CCS, we are taking a critical step towards achieving our emissions intensity reduction target of 35% by 2030. A number of projects were delivered in the last year that reduced emissions intensity at our operated assets. These included the installation of advanced process control at the Otway Gas Plant and the reduction of flare purge gas at our Middleton facility in the Cooper Basin and at Yolla, our BassGas offshore platform. More detail on these activities is provided in Beach’s FY23 Sustainability Report. Beyond decarbonisation, Beach continues to assess a range of new energy opportunities where it makes sense for our assets and our shareholders. FY24 outlook FY24 will be a significant year for Beach, with major projects being delivered and progressed across our portfolio. Planned activities this year include: – Progressing the Waitsia Stage 2 project; – Perth Basin gas exploration and development drilling; – Connecting the Enterprise discovery to the Otway Gas Plant; – Drilling the Kupe South 9 development well in the Taranaki Basin; – Ongoing oil and gas exploration, appraisal and development drilling in the Cooper Basin; – Planning for the next phase of offshore Victoria drilling; and – Working with joint venture partner Santos to progress Moomba CCS. Conclusion Since our last Annual Report, the topic of domestic gas in Australia has been front and centre in the national debate. There has been a significant level of intervention by the Federal Government with the intent of bringing down energy prices for households and businesses. We see these interventions as unnecessary and potentially harmful, with unintended consequences already evident such as slowing investment in exploration and development which will reduce future gas supply and may only serve to increase energy prices. We believe that creating an environment that encourages more gas to be developed for Australia is a better solution. What I am most proud of at Beach is our exceptional workforce. We have made a resolute commitment to fostering a strong culture within our company, one that attracts and inspires top talent from across our industry. The excellent safety performance of our employees and contractors this year serves as a testament to the significant improvements we have achieved in our safety culture at Beach. However, we cannot afford to become complacent. Every single day, our Beach team pursues our Purpose of 'Sustainably Delivering Energy to Communities'. The energy we produce is indispensable for facilitating the transition to cleaner technologies. This dedicated effort keeps our communities functioning, drives the success of our businesses, and provides heat to our homes. To you, our valued shareholder, I look forward to fulfilling the growth promises that Beach has committed to in recent years. FY24 marks a pivotal period in which we plan to deliver major projects to grow production and cash flows in a sustainable manner. Regards, Bruce Clement Interim CEO 14 August 2023 15 Board of Directors Glenn Davis Independent Non-Executive Chairman LLB, BEc, FAICD Bruce Clement Executive Director and Interim Chief Executive Officer BEng (Civil) Hons, BSc, MBA Sally‑Anne Layman Independent Non-Executive Director BEng (Mining) Hon, BCom, CPA, MAICD Mr Davis has practised as a solicitor in corporate and risk throughout Australia for over 35 years, initially in a national firm and then a firm he founded. He has expertise and experience in the execution of large transactions, risk management and in corporate activity regulated by the Corporations Act (2001) and ASX Limited. Mr Davis has worked in the oil and gas industry as an advisor and director for over 25 years. Mr Davis is currently a non-executive director and Chair of iTech Minerals Ltd (since 2021), Adrad Holdings Pty Ltd (since January 2022) and SkyCity Entertainment Group Limited (since September 2022). Mr Davis’s special responsibilities include membership of the Remuneration and Nomination Committee. Mr Davis joined Beach on 6 July 2007 as a non-executive director. He was appointed Non-Executive Deputy Chairman in June 2009 and Chairman in November 2012. He was last re-elected to the Board on 25 November 2020. Mr Clement was appointed a non-executive director of Beach on 8 May 2023 and Interim Chief Executive Officer and an executive director on 9 August 2023. Mr Clement has over 40 years of domestic and international energy industry experience. He has managed oil and gas exploration, development and production operations in Australia and Asia and has delivered key projects across these regions and in the UK and US. He also has extensive experience and knowledge of the Perth Basin, including overseeing the discovery of the Waitsia gas field as Managing Director of AWE. Mr Clement previously held engineering, senior management, and board positions with several companies including Santos, Norwest Energy, AWE, ExxonMobil and Roc Oil. He is currently a non-executive director of Horizon Oil. Mr Clement holds a Bachelor of Engineering (Civil) Hons and a Bachelor of Science (Maths & Computer Science) from Sydney University and a Masters of Business Administration from Macquarie University. Sally-Anne Layman is a company director with diverse international experience in the resources sector and financial markets. Previously, Ms Layman held a range of senior positions with Macquarie Group Limited, including as Division Director and Joint Head of the Perth office of the Metals, Mining & Agriculture Division. Prior to moving into finance, Ms Layman undertook various roles with resource companies including Mount Isa Mines, Great Central Mines and Normandy Yandal. Ms Layman holds a WA First Class Mine Manager’s Certificate of Competency. Ms Layman is also a Non-Executive Director of Imdex Ltd, Pilbara Minerals Ltd and Newcrest Mining Ltd. Ms Layman holds a Bachelor of Engineering (Mining) Hon from Curtin University and a Bachelor of Commerce from the University of Southern Queensland. Ms Layman is a Certified Practicing Accountant and is a member of CPA Australia Ltd and the Australian Institute of Company Directors. Ms Layman is Chair of the Audit Committee and a member of the Remuneration and Nomination Committee and the Risk, Corporate Governance and Sustainability Committee. She was appointed to the Board in February 2019 and re-elected to the Board on 16 November 2022. 16 Beach Energy Limited Annual Report 2023 Dr Peter Moore Independent Non-Executive Director Richard Richards Non-Executive Director PhD, BSc (Hons), MBA, GAICD BComs/Law (Hons), LLM, MAppFin, CA, Admitted Solicitor Ryan Kerry Stokes, AO Non-Executive Director BComm, FAIM Dr Moore has over 40 years of oil and gas industry experience. His career commenced at the Geological Survey of Western Australia, with subsequent appointments at Delhi Petroleum Pty Ltd, Esso Australia, ExxonMobil and Woodside. Dr Moore joined Woodside as Geological Manager in 1998 and progressed through the roles of Head of Evaluation, Exploration Manager Gulf of Mexico, Manager Geoscience Technology Organisation and Vice President Exploration Australia. From 2009 to 2013, Dr Moore led Woodside’s global exploration efforts as Executive Vice President Exploration. In this capacity, he was a member of Woodside’s Executive Committee and Opportunities Management Committee, a leader of its Crisis Management Team, Head of the Geoscience function and a director of ten subsidiary companies. From 2014 to 2018, Dr Moore was a Professor and Executive Director of Strategic Engagement at Curtin University’s Business School. He has his own consulting company, Norris Strategic Investments Pty Ltd. Dr Moore is currently a non-executive director of Carnarvon Petroleum Ltd (since 2015). Dr Moore's special responsibilities include chairmanship of the Remuneration and Nomination Committee and the Risk, Corporate Governance and Sustainability Committee and membership of the Audit Committee. Dr Moore was appointed by the Board on 1 July 2017 and last re-elected to the Board on 16 November 2022. Mr Richards has been Chief Financial Officer of SGH since October 2013. He is a director of SGH Energy and is a director and Chair of the Audit and Risk Committee of WesTrac Pty Limited and Coates Hire Pty Limited. He is a director of Boral Limited and is a member of their Audit and Risk and Safety Committees and he is also a director of Flagship Property Holdings. Mr Stokes is the Managing Director and Chief Executive Officer of SGH. SGH is a leading Australian diversified operating and investment group with market leading businesses and investments in industrial services, media and energy. This includes WesTrac Pty Limited, Coates Hire Pty Limited, Boral Limited (72.6%), Seven West Media Limited (39%), and Beach (30%). Mr Richards joined SGH from the diverse industrial group, Downer EDI, where he was Deputy Chief Financial Officer responsible for group finance across the company for three years. Prior to joining Downer EDI, Mr Richards was Chief Financial Officer for the Family Operations of LFG, the private investment and philanthropic vehicle of the Lowy Family for two years. Prior to that, Richard held senior finance roles at Qantas for over 10 years. Mr Richards is a former director and the Chair of Audit and Risk Management Committee of KU – established in 1895 as the Kindergarten Union of New South Wales, KU is one of the most respected childcare providers in Australia. He was also a member of the Marcia Burgess Foundation Committee. Mr Richards is both a Chartered Accountant and admitted solicitor with over 30 years of experience in business and complex financial structures, corporate governance, risk management and audit. Mr Richards’ special responsibilities include membership of the Audit Committee and of the Risk, Corporate Governance and Sustainability Committee. He was appointed to the Board on 4 February 2017 and was last re-elected to the Board on 25 November 2020. Mr Stokes is Chair of WesTrac, Coates, Boral, and a non-executive director of Seven West Media. Mr Stokes is Chief Executive Officer of Australian Capital Equity (ACE). ACE is a private company with its primary investment being an interest in SGH. Mr Stokes is Chairman of the National Gallery of Australia and is an Officer of the Order of Australia. Mr Stokes is an executive director of SGH (since 2010) and a non-executive director of Seven West Media (since 2012) and Boral Limited (since September 2020). Mr Stokes' special responsibilities include membership of the Remuneration and Nomination Committee. Mr Stokes was appointed to the Board on 20 July 2016 and ceased to be a director in November 2021. He was then appointed an alternate director for Margaret Hall on 1 December 2021 and ceased to be an alternate director on 23 July 2023. Mr Stokes was re-appointed to the Board on 23 July 2023. Margaret Hall Alternative Director for Mr Ryan Stokes B Eng (Met) (Hons), GAICD, MIEAust, SPE Ms Hall was appointed Alternate Director for Mr Stokes on 23 July 2023. Biographical details regarding Ms Hall are set out within the Director's Report on page 50. 17 Executive Team Bruce Clement Executive Director and Interim Chief Executive Officer Anne-Marie Barbaro Chief Financial Officer Ian Grant Chief Operating Officer Dr Sam Algar Group Executive Exploration and Subsurface BEng (Civil) Hons, BSc, MBA B Com, CA (ANZ) MSc, CMgr FCMI, GAICD BA (Hons), PhD Mr Clement was appointed a non-executive director of Beach on 8 May 2023 and Interim Chief Executive Officer and an executive director on 9 August 2023. Mr Clement has over 40 years of domestic and international energy industry experience. He has managed oil and gas exploration, development and production operations in Australia and Asia and has delivered key projects across these regions and in the UK and US. He also has extensive experience and knowledge of the Perth Basin, including overseeing the discovery of the Waitsia gas field as Managing Director of AWE. Mr Clement previously held engineering, senior management, and board positions with several companies including Santos, Norwest Energy, AWE, ExxonMobil and Roc Oil. He is currently a non-executive director of Horizon Oil. Mr Clement holds a Bachelor of Engineering (Civil) Hons and a Bachelor of Science (Maths & Computer Science) from Sydney University and a Masters of Business Administration from Macquarie University. Ms Barbaro joined Beach in 2018 in the role of Group Manager Planning and Reporting and was subsequently promoted to General Manager Finance in 2019 and Acting Chief Financial Officer in November 2021. Ms Barbaro was appointed Chief Financial Officer in July 2022, and is responsible for the finance, tax, treasury, IT, contracts and procurement, insurance, internal audit, and investor relations functions. Ms Barbaro is a Chartered Accountant with over 20 years’ experience in the accounting industry, including 12 years in the oil and gas sector. Prior to this, Anne-Marie held roles at Santos across Finance and Marketing and Trading, as well as finance roles at Australian Naval Infrastructure and PwC. Morné Engelbrecht Chief Executive Officer BCom (Hons), CA (ANZ), MAICD Mr Engelbrecht joined Beach in 2016 as Chief Financial Officer and in November 2021 he was promoted to the Chief Executive Officer role in an acting capacity. In May 2022 he was confirmed in the role(1). In November 2021, he was appointed to the board of the Australian Petroleum Production & Exploration Association (APPEA) and serves as Vice Chair of APPEA. Mr Grant has over 25 years’ experience in the energy industry, having held senior leadership and executive roles in operations, projects, drilling and supply chain functions. Born in Scotland, Mr Grant has extensive North Sea experience and has worked in Europe and Australia with companies such as Mobil, ARCO/BP, Apache, Quadrant Energy and Santos. Most recently Mr Grant was Chief Operating Officer for Quadrant Energy and Vice President of Production Operations for Santos based in Perth. He is passionate about delivering operations excellence and commercial performance in both onshore and offshore environments. Dr Algar joined Beach in February 2021 and brings over 30 years’ experience in the energy industry, having held senior leadership and executive roles in Australia and internationally, including the UK, Indonesia, Malaysia, Canada and the USA, looking after global exploration, new venture and subsurface portfolios. Most recently Dr Algar was Senior Vice President, Subsurface and Exploration with Oil Search Limited. Dr Algar holds a Bachelor of Arts (Hons) Geology from Oxford University and a PhD Geology from Dartmouth College in the USA. Previous employers include Ophir Energy, Murphy Oil, ENI, LASMO and Enterprise Oil. Mr Engelbrecht has 23 years of experience in the oil & gas and resource sectors across various jurisdictions including Australia, South Africa, the United Kingdom, Papua New Guinea and China. Prior to this he held various financial, commercial and advisory senior management positions at InterOil, Lihir Gold (merged with Newcrest), Harmony Gold and PwC. (1) Mr Engelbrecht's tenure as Chief Executive Officer ended on 9 August 2023. 18 Beach Energy Limited Annual Report 2023 Brett Doherty Group Executive Health, Safety, Environment and Risk Susan Jones General Counsel BEng (Electrical), LLB (Hons) LLB (Hons) Sam Bradley Group Executive People and Culture BBus (HR & IR) Paul Hogarth Acting Group Executive Corporate Strategy and Commercial BCom Mr Doherty joined Beach in February 2018 as Group Executive Health, Safety, Environment and Risk, bringing over 30 years of upstream oil and gas experience to Beach. His career includes extensive exposure to both offshore and onshore development and operations. Prior to Beach, Mr Doherty was General Manager of Health, Safety and Environment at INPEX Australia. He has held several senior international positions during his career, including ten years as the Chief HSEQ Officer at RasGas Company Limited, in the State of Qatar. Ms Bradley joined Beach in March 2023, bringing over 25 years’ experience in the Human Resources field, including 10 years in the downstream energy sector with AGL. Most recently, Ms Bradley was the Chief People & Culture Officer for People’s Choice Credit Union and has previously held senior leadership roles across multiple industries including Manufacturing, Energy, Education, NFP and Financial Services. Ms Bradley is passionate about building strong, resilient cultures that are change ready with values led leadership capability. Ms Jones joined Beach in February 2021 and was appointed General Counsel in August 2021. She has over 25 years' experience having worked in Australia, USA, UK and northern Africa in legal and non-legal roles. Her legal experience covers all aspects of legal operations, M&A, project finance, commodity sales and compliance. She has also held senior commercial and asset management roles. Previous employers include Total, Woodside, BHP and Ophir. In addition to her in-house experience, Ms Jones has worked at Sidleys (New York) and King Wood Mallesons (Australia). Ms Jones is originally from South Australia and holds a first class honours LLB. In addition to being admitted to practice law in Australia she is admitted to practice law in New York. Mr Hogarth has over 25 years of international energy industry experience working in senior commercial, marketing, business development, mergers, acquisitions & divestments and strategy roles in Australia, Europe, Asia, Africa and the USA. Mr Hogarth joined Beach in October 2018 as General Manager Commercial & Marketing and previously worked for Shell, BG Group and Woodside. He has deep experience in global energy markets across the energy value chain (upstream, midstream and downstream) and core expertise in energy market entry and commercialisation of energy products, including LNG, pipeline gas, oil, condensate, LPG and electricity. Mr Hogarth holds a Bachelor of Commerce from Curtin University. 19 Operations Review Performance overview Production 2P Reserves 2C Contingent Resources Sales revenue Statutory net profit after tax Underlying net profit after tax Statutory earnings per share Underlying earnings per share Cash flow from operating activities Net assets Net debt/(cash) Net gearing ratio Fully franked dividends declared per share Shares on issue Share price at year end Market capitalisation at year end Production Perth Basin Otway Basin (Victoria) Otway Basin (South Australia) Bass Basin Cooper Basin Western Flank Cooper Basin Joint Venture Cooper Basin Other Taranaki Basin Total 20 MMboe MMboe MMboe $ million $ million $ million cps cps $ million $ million $ million % cents million $ $ million FY22 Oil equivalent (MMboe) Oil (MMbbl) 1.3 4.1 0.1 1.1 5.2 7.1 0.1 2.8 21.8 – – – – 2.8 1.0 0.0 – 3.7 FY19 29.4 326 185 1,925 577 560 25.4 24.6 1,038 2,374 (172) n/a 2.0 2,278 1.985 4,522 Sales Gas (PJ) 9.0 22.1 0.1 3.9 4.2 27.5 0.4 9.1 76.4 FY20 26.7 352 180 1,650 499 459 21.9 20.2 874 FY21 25.6 339 191 1,519 317 363 13.9 15.9 760 2,818 3,088 (50) n/a 2.0 2,281 1.520 3,467 48 1.5 2.0 2,281 1.240 2,829 FY22 FY23 21.8 283 221 19.5 255 195 1,749 1,617 501 504 22.0 22.1 1,223 3,540 (165) n/a 2.0 2,281 1.725 3,935 401 385 17.6 16.9 929 3,878 166 4.1 4.0 2,281 1.350 3,080 FY23 LPG (kt) Condensate (kbbl) Oil equivalent (MMboe) Year-on-year change – 43 – 8 20 57 1 39 – 325 – 135 152 434 10 221 1.6 4.5 0.0 0.9 3.8 6.6 0.1 2.1 169 1,277 19.5 21% 9% (81%) (21%) (27%) (7%) (35%) (25%) (11%) Beach Energy Limited Annual Report 2023 Finance Maintained financial strength to support future growth and capital management initiatives In FY23, Beach continued to focus on safely delivering its major growth projects while maintaining strict focus on costs and capital expenditure across the business. A new dividend policy of 40–50% payout of pre-growth free cash flow was implemented during the year, resulting in a 100% increase in full year dividends to 4.0 cents per share. Sales revenue was 8% down to $1.6 billion due to lower production and liquids prices partly offset by higher gas prices, up 9% to $8.8/GJ, and lower exchange rates. This impacted underlying earnings before interest, tax, depreciation and amortisation (EBITDA), down 12% to $1.0 billion, underlying net profit after tax (NPAT), down 24% to $385 million, and cash flows from operating activities down 24% to $929 million. Net assets increased by $338 million to $3.9 billion. Beach ended the year with net debt of $166 million, comprising cash reserves of $219 million less drawn debt of $385 million, despite heightened capital spend to deliver the Otway and Perth basin growth projects which contributed to group capital expenditure of $1.1 billion. The company remains well positioned to deliver its current projects while balancing future growth aspirations with capital management initiatives. Beach has a demonstrated track record of prudent balance sheet management, including deploying capital for investment, only when there is clear line of sight to sustainable value creation. This disciplined focus on capital management will continue as the company embarks on an active FY24. Beach is well positioned to deliver its current projects while balancing future growth aspirations with capital management initiatives. Revenue $1.6 billion Underlying EBITDA $1.0 billion Dividends declared 4.0 cps Lang Lang Gas Plant 21 Waitsia Gas Plant Operations Review Perth Basin Contribution FY23 Production 8% 2P Reserves 34% FY23 Highlights FY24 Focus Over five years recordable injury free at the Beharra Springs Gas Plant; 99.6% plant reliability Completed the six-well Waitsia Stage 2 development drilling program Signed a SPA with bp to deliver up to 3.75 Mt of LNG from the Waitsia field Progressed Waitsia Gas Plant construction Gas exploration success in the Gynatrix field Commenced Beach-operated gas exploration campaign Progress construction of the Waitsia Gas Plant Progress the Perth Basin gas exploration campaign Progress the Beharra Springs permeate recovery project Delivering new gas supply for the Australian West Coast and global LNG markets 22 Beach Energy Limited Annual Report 2023 Development Exploration and appraisal The Waitsia Stage 2 project is a key driver of Beach’s growth strategy and aims to develop existing gas reserves for both the domestic Western Australia market and the global LNG market. The six-well Waitsia Stage 2 development drilling campaign was completed in October 2022 with five wells completed as future producers. Construction of the 250 TJ/day Waitsia Gas Plant continued throughout the year. Several milestones were achieved including tie-in to the Karratha Gas Plant and installation of the amine system including the CO2 absorber, amine stripper, circulation pumps, inlet separator and stabilisation unit and four export gas compressors. As announced on 6 February 2023, agreement was reached with Webuild for Webuild to complete delivery of the Waitsia Stage 2 project. Webuild’s acquisition of Clough Limited and its personnel, systems and processes helped project execution continue during the Clough voluntary administration process. The voluntary administration process and tight labour market in Western Australia impacted construction progress. To mitigate the effect on the delivery schedule, various actions were identified and implemented including new accommodation camps, a new employment agreement, elevated recruiting activity, extended 12-hour shifts and new night operations. The Perth Basin gas exploration campaign commenced in November 2022 with the first two wells of the campaign, Elegans 1 and Gynatrix 1, drilled in the L2 and L1 Mitsui- operated permits. Elegans 1 failed to intersect gas and was plugged and abandoned. Gynatrix 1 intersected six metres of net gas pay across a 37-metre gross section in the target Kingia formation. Production testing will be undertaken in FY24. The first Beach-operated well of the gas exploration campaign, Trigg 1, was drilled to a total depth of 4,914 metres (measured depth). Gas shows were present in the primary Kingia target however no gas could be recovered with wireline testing and the well was plugged and abandoned. The second well of the campaign, Trigg Northwest 1, spudded after year-end. Commercial On 8 August 2022, Beach announced execution of the LNG SPA with bp. The LNG SPA will see bp purchase up to 3.75 Mt of Beach’s expected LNG volumes from the Waitsia Stage 2 project. The LNG SPA contains a hybrid pricing structure linked to both Brent oil and JKM indices with downside price protection and no restriction on upside price participation. Acreage description Perth Basin producing licence areas include Waitsia (Beach 50%, MEPAU 50% and operator) in licences L1 and L2, and Beharra Springs (Beach 50% and operator, MEPAU 50%) in licences L11 and L22. The exploration permit is EP 320 (Beach 50% and operator, MEPAU 50%). Production Total production of 1.6 MMboe was 21% above the prior year (FY22: 1.3 MMboe) and comprised 9.0 PJ of sales gas. Higher production was due to high plant uptime rates and strong customer demand. 1.6 MMboe FY23 Production 2022 | 1.3 MMboe 86.5 MMboe 2P Reserves 2022 | 98.6 MMboe 23 Operations Review Otway Basin (Victoria) Contribution FY23 Production 23% 2P Reserves 25% Otway Gas Plant Production Total production of 4.5 MMboe was 9% above the prior year (FY22: 4.1 MMboe) and comprised 22.1 PJ of sales gas (+8%), 43 kt of LPG (+23%) and 325 kbbl of condensate (+13%). The increase in production was mostly attributable to connection of the Geographe 4 and 5 development wells in early 2022 and the Thylacine North 1 and 2 development wells in mid-2023 to the Otway Gas Plant. This increased well deliverability was partially offset by Otway Gas Plant downtime for well tie-in activities, scheduled maintenance and variable customer nominations. FY23 Highlights FY24 Focus Safe completion of the seven-well offshore drilling campaign Eight years recordable injury free achieved at the Otway Gas Plant; 99.8% plant reliability Connected Thylacine North 1 and 2 development wells to the Otway Gas Plant Progressed connection of the Enterprise discovery to the Otway Gas Plant Secured consortium rig for next phase of offshore activity Completed Otway CCS pre-feasibility study Recipient of the 2023 APPEA Safety Project Excellence Award Connect the Enterprise discovery to the Otway Gas Plant Progress connection of the Thylacine West 1 and 2 development wells Progress planning for the next phase of offshore activity Progress the Otway CCS feasibility study Demonstrated capability in delivering new gas supply for the Australian East Coast market 24 Development Beach completed its first major offshore drilling campaign in July 2022 which delivered one gas discovery at the Artisan field and six successful development wells in the Geographe and Thylacine fields. Beach was the only Australian offshore operator to drill continuously through the COVID-19 pandemic, delivering a campaign that required approximately 820,000 operational hours. Beach and its contractors received the 2021 IADC Safety Award for outstanding safety performance and the 2023 APPEA Safety Project Excellence Award for offshore COVID and mental health management during the Otway Basin drilling campaign. Following connection of the first two development wells in early 2022 (Geographe 4 and 5), the Thylacine North 1 and 2 development wells were connected to the Otway Gas Plant in May 2023. This increased well deliverability to the Otway Gas Plant and enabled delivery of additional gas into the East Coast market. During the connection activities, a hydro pressure test failure occurred which impacted timing for connection of the final two development wells, Thylacine West 1 and 2. Beach is targeting connection of these wells in H1 FY25, subject to securing a vessel. Associated costs are expected to be largely recoverable. A root cause analysis of the hydro pressure test failure was underway at year-end. Beach progressed connection activities for the nearshore Enterprise discovery and is targeting first gas in H2 FY24, subject to final approvals. Progress included completion of pipeline construction and laying, tie-in activity at the Otway Gas Plant and Christmas tree installation at the well site. The Enterprise discovery was drilled from an onshore well pad in FY21. The discovery yielded liquids-rich gas and de-risked existing nearshore exploration prospects. At year-end, discussions were continuing with Native Title holders in relation to land access. Conclusion of this process will allow for final regulatory approvals to complete wellsite works.1 First gas from Enterprise in H2 FY24 is targeted, subject to final approvals. Beach Energy Limited Annual Report 2023 Otway Basin (South Australia) Otway CCS FY23 Highlights FY24 Focus Beach completed a pre-feasibility study for a CCS opportunity in the Otway Basin and was progressing the Select phase at year-end. This involves refining the pre-feasibility study to further clarify storage capacity, reservoir selection, injectability, integration and environmental approvals. This phase is expected to conclude in the first half of FY24 when a decision on whether to proceed to FEED will be made. Progressed analysis of the Dombey 3D seismic survey Katnook Gas Plant available for future exploration and development activity Finalise interpretation of the Dombey 3D seismic survey Identify opportunities for future exploration and development activity Assessing future exploration and development opportunities Production Total production of 22 kboe was 81% below the prior year (FY22: 119 kboe) and comprised 0.1 PJ of sales gas (-81%). Production at the Katnook Gas Plant was suspended in Q1 FY23. The plant will be kept available for production in the event of future development or exploration success. Exploration and appraisal Processing of the Dombey 3D seismic survey continued throughout the year. The survey covers 165 square kilometres in PEL 494 and captures the Dombey field and surrounding exploration prospects. It will allow assessment of opportunities to supply gas to the Katnook Gas Plant. Acreage description Otway Basin (South Australia) comprises producing licences PPLs 62, 168 and 202 (Beach 100%), and retention licences PRL 32 (Beach 70% and Cooper Energy 30%) and PRLs 1 and 2 (Beach 100%), and exploration licences PEL 494, which contains the Dombey gas field, and PEL 680 (Beach 70% and Cooper Energy 30%). Otway Basin (South Australia) also comprises gas storage licences GSEL 654 (Beach 70% and Cooper Energy 30%) and GSRL 27 (Beach 100%), as well as a geothermal licence, GEL 780 (Beach 100%). 4.5 MMboe FY23 Production 2022 | 4.1 MMboe 62.9 MMboe 2P Reserves 2022 | 67.4 MMboe 25 Exploration and appraisal Exploration and appraisal activity focused on amplitude supported prospects in both offshore and nearshore acreage. Beach progressed 3D seismic activity, and matured offshore exploration prospects throughout the year. To enable the next phase of exploration and development activity, Beach participated in a consortium which secured the Transocean Equinox drill rig for offshore activity in 2025 and potentially beyond. Early planning is underway to develop a works schedule in conjunction with consortium members. Beach’s activity is expected to include development of the Artisan and La Bella discoveries and exploration drilling. Confirmation of schedule, prospects and number of wells to be drilled is subject to completion of seabed assessments, joint venture and regulatory approvals and a final investment decision. Acreage description Otway Basin (Victoria) (Beach 60% and operator, OGOG (Otway) Pty Ltd 40%) includes producing nearshore licence VIC/L1(V) which contains the Halladale, Black Watch and Speculant gas fields, nearshore production licence VIC/L007745(V), containing the Enterprise gas field, and offshore licences VIC/L23, T/L2, T/L3 and T/L4 which contain the Geographe and Thylacine gas fields. Gas from all producing fields is processed at the Otway Gas Plant. Otway Basin (Victoria) also comprises non-producing nearshore VIC/P42(V) (Beach 60% and operator, OGOG (Otway) Pty Ltd 40%), and offshore licences VIC/P43 (Beach 60% and operator, OGOG (Otway) Pty Ltd 40%), containing the Artisan gas discovery, VIC/P73 (Beach 60% and operator, OGOG (Otway) Pty Ltd 40%), containing the La Bella gas field and T/30P (Beach 100%). It also comprises the nearshore exploration permit VIC/P007192(V) (Beach 60% and operator, OGOG (Otway) Pty Ltd 40%2), onshore exploration permit PEP 168 (Beach 50% and operator, Essential Petroleum Exploration 50%), and onshore production licences PPLs 6 and 9 (Lochard Energy 90% and operator, Beach 10%). 1 2 In July 2022, the Victorian Government determined that the granting of the Petroleum Special Drilling Authorisation (PSDA) for Enterprise would be considered a ‘future act’ under the Native Title Act 1993, triggering the Right to Negotiate process. Pending approval. Lang Lang Gas Plant Operations Review Bass Basin Contribution FY23 Production 4% 2P Reserves 2% FY23 Highlights FY24 Focus Complete interpretation of the Prion 3D seismic survey Progress development planning, costings and economics for Trefoil, White Ibis, Bass and Yolla West Two years recordable injury free at the Lang Lang Gas Plant Lang Lang Gas Plant reliability of ~98% following maintenance activities Progressed Prion 3D seismic survey interpretation over the Trefoil, White Ibis and Bass discoveries Progressed assessment of development options for existing discoveries and the Yolla West infield opportunity Completed Yolla 6 wireline intervention work 26 Beach Energy Limited Annual Report 2023 Production Total production of 0.9 MMboe was 21% below the prior year (FY22: 1.1 MMboe) and comprised 3.9 PJ of sales gas (-19%), 8 kt of LPG (-40%) and 135 kbbl of condensate (-19%). Lower production was mainly due to downtime for planned and unplanned maintenance and natural field decline. 0.9 MMboe FY23 Production 2022 | 1.1 MMboe 4.2 MMboe 2P Reserves 2022 | 4.8 MMboe Progressing development opportunities to unlock new gas supply for the East Coast market Development Planning for the potential next phase of development continued throughout the year. Activity included cost analysis and interpretation of the Prion 3D seismic survey acquired over the White Ibis, Bass and Trefoil discoveries and review of the Yolla West infield opportunity. Acreage description Bass Basin operations include production from the Yolla field, situated approximately 140 km off the Gippsland coast in licence T/L1 (Beach 88.75% and operator, Prize Petroleum 11.25%). Gas from the Yolla field is piped to the Lang Lang Gas Plant located near the township of Lang Lang, approximately 70 km southeast of Melbourne. Beach also holds a 90.25% operated interest in licences T/RL2 (pending production licence application), T/RL4 and T/RL5, which capture the Trefoil, White Ibis and Bass discoveries. 27 Cooper Basin Western Flank Operations Review Cooper Basin Western Flank Contribution FY23 Production 19% 2P Reserves 7% FY23 Highlights FY24 Focus Deliver drilling campaign with a greater focus on exploration and appraisal Ongoing production optimisation and performance improvement initiatives Delivered the FY23 drilling campaign in a year with significant flooding and weather-related challenges Drilled 16 horizontal oil development wells with total lateral sections of ~20 km Drilled seven oil exploration and appraisal wells at a success rate of 71% Completed Martlet facility capacity expansion Delivered the Birkhead fracture stimulation pilot project Greater exploration and appraisal planned following successful development activities in FY23 28 Beach Energy Limited Annual Report 2023 Development Exploration and appraisal Beach drilled 17 oil development wells including 16 horizontal wells with an overall success rate of 94%. Major development campaigns focused on the Bauer, Growler and Spitfire fields. A six-well horizontal oil development campaign in the Growler and Spitfire fields delivered five producers. Spitfire 13 came in low to prognosis with results indicating sections of swept reservoir from nearby producing wells. The well was side-tracked and Spitfire 13 DW1 was cased and suspended as a producer. A two-well follow-up campaign commenced with Spitfire 10 drilling ahead at year-end. A seven-well oil development campaign targeting the McKinlay Member and Namur Sandstone in the Bauer and Arno fields was completed with six horizontal wells and one vertical well completed and brought online. Bauer 71 DW1 was drilled from the Bauer 71 wellbore to enable co-mingled production from both lateral sections, saving cost and time. Single horizontal wells were drilled in the Balgowan, Callawonga, Kangaroo and Rincon fields with Balgowan 8 cased and suspended as a producer and Callawonga 23, Kangaroo 3 and Rincon 4 completed and brought online. A Birkhead reservoir fracture stimulation pilot project was delivered, focusing on four vertical oil wells in the Bauer and Kangaroo fields and single horizontal oil wells in the Kangaroo and Stunsail fields. The campaign provided encouraging results which support assessment of a second phase of Birkhead horizontal fracture stimulation. Two vertical oil exploration wells targeting the Birkhead reservoir and one targeting the Namur reservoir were drilled with Rocky 1 discovering approximately three metres of net oil pay. This result indicates oil migration west of existing commercial fields and will help inform a Birkhead exploration campaign planned for FY24. Knapmans 1 and Chiton Southeast 1 were plugged and abandoned with sub-commercial oil pay. A four-well oil appraisal drilling campaign was conducted in the Martlet field which followed successful appraisal drilling in FY22. The campaign delivered four producers with work completed on facility capacity expansion. Acreage description Western Flank oil producing assets include ex PEL 91 (Beach 100%), ex PEL 104/111 (Beach 100%) and ex PEL 92 (Beach 75% and operator, Cooper Energy 25%). Western Flank gas producing assets include ex PEL 106 (Beach 100%) and the Udacha Block – PRL 26 (Beach 100%). Non-producing assets include ex PEL 101 (Beach 100%), ex PEL 182 (Beach 100%) and ex PEL 107 (Beach 100%). Beach also owns gas storage assets including GSEL 634 (Beach 75% and operator, Cooper Energy 25%), and GSELs 645, 646, 648 and 653 (all Beach 100%). Production Total production of 3.8 MMboe was 27% below the prior year (FY22: 5.2 MMboe) and comprised 2.8 MMbbl of oil (-20%), 4.2 PJ of sales gas (-38%), 20 kt of LPG (-44%) and 152 kbbl of condensate (-47%). The decrease in oil production was primarily attributable to flooding in the Cooper Creek, weather related downtime and challenges arising from changes to the drilling schedule due to rain delays. Lower gas and associated liquids production was due to natural field decline. 3.8 MMboe FY23 Production 2022 | 5.2 MMboe 18.5 MMboe 2P Reserves 2022 | 22.2 MMboe 29 Moomba Gas Plant, Cooper Basin, South Australia Operations Review Cooper Basin JV Contribution FY23 Production 34% 2P Reserves 25% FY23 Highlights FY24 Focus Participated in 117 wells with an overall success rate of 93% 4–5 rig drilling campaign with a focus on gas development Gas exploration success at the Coloy and Europa fields Increased oil activity with 27 appraisal and development wells drilled Accelerated gas development drilling with fifth rig utilised Progressed the Moomba CCS project; ~70% complete Ongoing production and performance improvement initiatives Progress the Moomba CCS project Ongoing electrification across the asset portfolio Accelerated oil and gas development while delivering the transformative Moomba CCS project 30 Beach Energy Limited Annual Report 2023 Development Moomba CCS Beach participated in 91 oil and gas development wells with an overall success rate of 96%. Major gas development campaigns focused on the Big Lake, Dullingari, Moomba and Swan Lake fields with a 13-well campaign in the Big Lake field and a 22-well campaign in the Moomba South field successfully completed. Major oil development campaigns focused on the shallow Coorikiana oil play in the Limestone Creek area, Narcoonowie and Zeus fields with 13 wells drilled and 12 brought online. Zeus 13 was plugged and abandoned with sub-commercial oil pay. An 11-well gas and oil development campaign in the Tirrawarra field progressed and delivered nine future producers with one well yet to be drilled. Exploration and appraisal Beach participated in 22 oil and gas appraisal wells with an overall success rate of 91%. Major drilling activity included completion of gas appraisal campaigns in the Moomba and Dorodillo fields and oil appraisal campaigns in the Ragno and Isoptera fields. Four gas exploration wells targeting the Toolachee and Patchawarra formations were drilled and delivered discoveries at Coloy 1 and Europa 1. Moomba CCS will deliver a material reduction in Beach’s CO2 emissions through use of depleted reservoirs to sequester up to 1.7 Mt of CO2 per year (gross), representing more than 0.5 Mt of CO2 per year net to Beach. All four Moomba CCS injector wells were successfully drilled and completed during the year. In addition, all earthworks and piling activities were completed and the CO2 compressor and flowlines were installed and tested. The Moomba CCS project remains on schedule for first injection in 2024, with 70% of works complete. Acreage description Beach owns non-operated interests in the South Australian Cooper Basin joint ventures (33.40% in SA Unit and 27.68% in Patchawarra East), the South West Queensland joint ventures (various interests of 30% to 52.5%) and ATP 299 (Tintaburra; Beach 40%), which are collectively referred to as the Cooper Basin JV. Santos is the operator. Production Total production of 6.6 MMboe was 7% below the prior year (FY22: 7.1 MMboe) and comprised 1.0 MMbbl of oil (+1%), 27.5 PJ of sales gas (-7%), 57 kt of LPG (-15%) and 434 kbbl of condensate (-17%). Natural field decline and a flowline outage affecting Big Lake and Moomba South production were partially mitigated by accelerated drilling and connection activity and various successful maintenance and optimisation initiatives. 6.6 MMboe FY23 Production 2022 | 7.1 MMboe 63.2 MMboe 2P Reserves 2022 | 68.2 MMboe 31 Operations Review Taranaki Basin Kupe Gas Plant Contribution Development FY23 Production 11% 2P Reserves 8% Beach completed subsurface analysis and planning for the Kupe South 9 development well. Final regulatory approvals were obtained and the Valaris 107 rig was contracted. If successful, Kupe South 9 has the potential to return the Kupe Gas Plant to capacity gas processing rates of 77 TJ/day. FY23 Highlights FY24 Focus No recordable safety incidents Kupe Gas Plant reliability >99% Completed subsurface analysis and regulatory approvals for the Kupe South 9 development well Secured the Valaris 107 rig to drill Kupe South 9 Completed the four-yearly Kupe Gas Plant amine system inspection and first inlet compressor inspection Drill and connect the Kupe South 9 development well Return the Kupe Gas Plant to capacity production rates Ongoing productivity and sustainability optimisation activities Progress Kupe onshore and offshore wind energy opportunities Delivering gas and liquids to support New Zealand’s energy transition 32 Beach Energy Limited Annual Report 2023 Wind power generation Acreage description The South Taranaki region has one of New Zealand's most attractive wind resources. Along with engaging with iwi and hapū, Beach has enlisted the support of an expert service provider to perform a feasibility study which includes engaging with landholders regarding a potential wind farm adjacent to the Kupe Gas Plant in which Beach could be a foundational customer and future partner. Additionally, Beach is partnering with a consortium of offshore wind developers to conduct a study into wind opportunities near to existing Kupe offshore infrastructure. New Zealand operations comprise the offshore Kupe field (Beach 50% and operator, Genesis 46%, NZOG 4%) in the Taranaki Basin. Beach produces gas from Kupe, situated approximately 30 km off the New Zealand north island coast in licence PML 38146. Gas from the Kupe field is piped to the onshore Kupe Gas Plant. Production Total production of 2.1 MMboe was 25% below the prior year (FY22: 2.8 MMboe) and comprised 9.1 PJ of sales gas (-24%), 39 kt of LPG (-23%) and 221 kbbl of condensate (-31%). Production was impacted by natural field decline, planned downtime for maintenance and inspection activities, and periods of heavy rainfall which supported hydro power generation and in turn lowered customer demand for gas. 2.1 MMboe FY23 Production 2022 | 2.8 MMboe 19.4 MMboe 2P Reserves 2022 | 21.5 MMboe 33 Reserves Statement Net to Beach at 30 June 2023 Beach ended the financial year with 254.7 MMboe of 2P oil and gas reserves (30 June 2022: 282.7 MMboe). The decrease was mainly attributable to production (-19.5 MMboe) and Perth Basin revisions (-10.6 MMboe). These revisions followed assessment of results from the Waitsia drilling campaign. Beach ended the financial year with 195.3 MMboe of 2C contingent resources (30 June 2022: 220.5 MMboe). The decrease was mainly attributable to removal of low permeability gas projects in the Perth Basin that are expected to require hydraulic fracture stimulation to unlock potential. The proportion of 2P developed reserves has increased to 55% (30 June 2022: 44%) reflecting the Cooper and Otway basin development programs completed during the year. 2P storage capacity of 4.4 Mt and 2C storage contingent resources of 11.6 Mt associated with the Moomba carbon capture and storage project remain unchanged. Key Metrics 1P reserves (MMboe) 2P reserves (MMboe) 3P reserves (MMboe) 2C contingent resources (MMboe) 2P reserves life (Years) Note YEJ21 YEJ22 YEJ23 183 339 531 191 13.2 1 146 283 466 221 12.9 118 255 405 195 13.1 34 Beach Energy Limited Annual Report 2023 1P Reserves Western Flank Oil Western Flank Gas Cooper Basin JV Perth Basin Otway Basin Bass Basin Taranaki Basin Total 1P Reserves Western Flank Oil Western Flank Gas Cooper Basin JV Perth Basin Otway Basin Bass Basin Taranaki Basin Total 2P Reserves Western Flank Oil Western Flank Gas Cooper Basin JV Perth Basin Otway Basin Bass Basin Taranaki Basin Total All Products (MMboe) YEJ22 Production Acquisition/ Divestment Exploration From Contingent Resources Other YEJ23 6.6 2.6 34.7 51.6 30.4 1.8 17.9 2.8 1.1 6.6 1.5 4.5 0.9 2.1 145.6 19.5 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.3 0.0 1.9 -0.4 0.0 -0.2 0.0 1.6 2.1 0.2 -1.7 -12.2 1.6 -0.1 0.0 ‑10.1 6.2 1.7 28.3 37.5 27.5 0.6 15.8 117.6 Gas (PJ) 0 7 130 218 136 3 68 562 LPG (kt) Condensate (MMbbl) Oil (MMbbl) Total Developed Undeveloped All Products (MMboe) 0 28 214 0 264 10 302 818 0.0 0.2 1.8 0.0 2.0 0.1 1.6 5.7 6.2 0.0 2.4 0.0 0.0 0.0 0.0 8.6 6.2 1.7 28.3 37.5 27.5 0.6 15.8 117.6 6.2 1.0 21.7 11.6 20.8 0.6 14.0 75.9 0.0 0.7 6.6 25.9 6.7 0.0 1.8 41.7 Note 2, 3 4 5 6 7, 8 9 10 Note 2, 3 4 5 6 7, 8 9 10 Note YEJ22 Production Acquisition/ Divestment Exploration From Contingent Resources Other YEJ23 All Products (MMboe) 2, 3 4 5 6 7, 8 9 10 18.7 3.5 68.2 98.6 67.4 4.8 21.5 2.8 1.1 6.6 1.5 4.5 0.9 2.1 282.7 19.5 -0.1 0.0 0.0 0.0 0.0 0.0 0.0 ‑0.1 0.1 0.0 0.1 0.0 0.0 0.0 0.0 0.2 0.5 0.0 5.5 -5.6 0.0 0.5 0.0 0.9 -0.3 0.0 -4.0 -5.0 0.0 -0.2 0.0 ‑9.5 16.1 2.4 63.2 86.5 62.9 4.2 19.4 254.7 35 Reserves Statement 2P Reserves Western Flank Oil Western Flank Gas Cooper Basin JV Perth Basin Otway Basin Bass Basin Taranaki Basin Total LPG (kt) Condensate (MMbbl) Oil (MMbbl) Total Developed Undeveloped All Products (MMboe) 0.0 0.4 3.7 0.0 4.7 0.7 2.0 11.5 16.1 0.0 5.3 0.0 0.0 0.0 0.0 16.1 2.4 63.2 86.5 62.9 4.2 19.4 14.9 1.6 44.8 15.4 42.8 4.2 16.7 1.2 0.8 18.4 71.1 20.1 0.0 2.7 21.4 254.7 140.4 114.3 Note 2, 3 4 5 6 7, 8 9 10 Gas (PJ) 0 10 294 503 311 19 84 0 43 454 0 593 60 369 1,221 1,519 All Products (MMboe) 2C Contingent Resources Note YEJ22 Acquisition/ Divestment To Reserves Other YEJ23 Gas (PJ) LPG (kt) Condensate (MMbbl) Oil (MMbbl) Total (MMboe) Western Flank Oil 2, 3 Western Flank Gas Cooper Basin JV Perth Basin Otway Basin Bass Basin Taranaki Basin Bonaparte Basin 4 5 6 7, 8 9 10 11 16.8 1.2 60.2 38.2 30.4 35.0 4.5 22.6 Total Conventional 208.9 Unconventional 12 11.6 Total 220.5 -0.7 0.0 0.0 0.0 0.0 0.0 0.0 0.0 ‑0.7 0.0 ‑0.7 -0.5 0.0 -5.5 3.8 0.0 -0.5 0.0 0.0 ‑2.7 0.0 ‑2.7 -2.7 0.0 18.9 -36.6 0.0 -0.8 0.0 0.0 12.9 1.2 73.6 5.4 30.4 33.7 4.5 22.6 ‑21.2 184.3 -0.6 11.0 0 4 0 21 342 326 32 172 143 18 128 839 38 0 59 405 78 0 889 199 0.0 0.3 2.8 0.0 0.5 6.1 0.8 0.6 11.1 3.0 12.9 0.0 9.5 0.0 0.0 0.0 0.0 0.0 12.9 1.2 73.6 5.4 30.4 33.7 4.5 22.6 22.4 184.3 0.0 11.0 ‑21.8 195.3 877 1,088 14.1 22.4 195.3 Note 13 YEJ22 Injection 3.1 3.1 0.0 0.0 Carbon Dioxide (Mt) Acquisition/ Divestment From Contingent Resources Other YEJ23 0.0 0.0 0.0 0.0 0.0 0.0 3.1 3.1 Carbon Dioxide (Mt) Acquisition/ Divestment From Contingent Resources Other YEJ23 0.0 0.0 0.0 0.0 0.0 0.0 4.4 4.4 YEJ22 Injection 4.4 4.4 0.0 0.0 Carbon Dioxide (Mt) YEJ22 11.6 11.6 Acquisition/ Divestment To Storage Capacity 0.0 0.0 0.0 0.0 Other YEJ23 0.0 0.0 11.6 11.6 Note 13 Note 13 1P Storage Capacity Cooper Basin Total 2P Storage Capacity Cooper Basin Total 2C Storage Contingent Resources Cooper Basin Total 36 Beach Energy Limited Annual Report 2023 Notes to the Reserves Statement Reserves and resources estimates are prepared in accordance with the 2018 update to the Petroleum Resources Management System (SPE-PRMS). Storage resources are prepared in accordance with the 2017 CO2 Storage Resources Management System (SPE-SRMS). Both systems are sponsored by the Society of Petroleum Engineers (SPE), World Petroleum Council, American Association of Petroleum Geologists, Society of Petroleum Evaluation Engineers, Society of Exploration Geophysicists, Society of Petrophysicists and Well Log Analysts and the European Association of Geoscientists & Engineers. The statement presents Beach’s net economic interest estimated at 30 June 2023 using a combination of probabilistic and deterministic methods. Each category is aggregated by arithmetic summation. Note that the aggregated 1P category may be a very conservative estimate due to the portfolio effects of arithmetic summation. Reserves are stated net of fuel, flare and vent at reference points generally defined by the custody transfer point of each product. Waitsia reserves include 30 PJ of fuel used for LNG processing through the NWS facilities in Karratha through to the end of 2028. Conversion factors used to evaluate oil equivalent quantities are sales gas and ethane: 171,940 boe per PJ, LPG: 8.458 boe per tonne, condensate: 0.935 boe per bbl and oil: 1 boe per bbl. The estimates are based on, and fairly represent, information and supporting documentation prepared by, or under the supervision of, Qualified Petroleum Reserves and Resources Evaluators (QPRRE) employed by Beach. The QPRRE are Scott Delaney, Paula Pedler, Mark Sales and Jason Storey, who are all members of SPE. The reserves statement, as a whole, is approved by Ms Paula Pedler (Head of Reservoir Engineering). Ms Pedler is employed by Beach and is a member of SPE; she has a Bachelor of Engineering (Honours) degree from the University of Adelaide and more than 30 years of relevant experience. The reserves statement has been issued with the prior written consent of Ms Pedler as to the form and context in which the estimates and information are presented. Beach prepares its reserves and resources estimates annually as specified in the Beach reserves policy. This policy also details the internal governance and external audit requirements of the reserves and resources estimation process. An independent audit of Beach’s reserves at 30 June 2023 was conducted by Netherland, Sewell & Associates Inc. (NSAI). In NSAI’s opinion the reserves estimates are reasonable when aggregated at the 1P, 2P and 3P levels and have been prepared in accordance with generally accepted petroleum engineering and evaluation principles set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the SPE. The audit encompassed 66% of 2P reserves, including 71% of developed reserves and 60% of undeveloped reserves. Contingent resources have not been audited. Material Reserves Changes Beach has disclosed material reserves changes throughout the year in accordance with continuous disclosure obligations. – Perth Basin Revisions (refer to ASX announcement #004/23, 31 January 2023: FY23 Second Quarter Activities Report). Material Contingent Resources Changes There are no material contingent resources changes. Notes (1) 2P reserves life is calculated as 2P reserves divided by annual production. (2) Western Flank oil reserves and resources are contained within the tenements listed in the table below. 1P (%) 2P (%) ex PEL 91 26 39 ex PEL 92 23 18 ex PEL 104/111 50 42 (3) Other includes PPL203, PPL209, PPL213, PPL214, PPL241, PPL251. (4) Western Flank gas reserves and resources are contained within the tenements listed in the table below. 1P (%) 2P (%) ex PEL 91/106, PRL 26 53 63 (5) Cooper Basin JV comprises Fixed Factor Agreement, Patchawarra East, SWQ Gas Unit, Naccowlah, Aquitaine B, Total 66, Tintaburra and ex PEL513/632. (6) Perth Basin reserves and resources are contained within L1/L2, L11/L22 and EP320. (7) Otway Basin reserves and resources are contained within the tenements listed in the table below. 1P (%) 2P (%) T/L2, T/L3, VIC/L23 VIC/L1(V), VIC/P42(V) 28 37 72 63 (8) Other includes VIC/P43, VIC/P73 and PPL62/168/202, PRL32, PEL494. (9) Bass Basin reserves and resources are contained within the tenements listed in the table below. Other 1 1 PPL270 47 37 Other – – 1P (%) 2P (%) (10) Taranaki Basin reserves and resources are contained within PML38146. (11) Bonaparte Basin reserves and resources are contained within NT/RL1. (12) Unconventional resources are contained within the Cooper Basin JV (Fixed Factor Agreement). (13) Storage capacity and resources are contained within GSL 1, GSL 2, GSL 3 and GSL 4. T/L1 100 100 T/RL2, T/RL4 – – 37 Directors’ Report Your directors present their report for Beach Energy Limited (Beach or Company) on the consolidated accounts for the financial year ended 30 June 2023. Beach is a company limited by shares that is incorporated and domiciled in Australia. The directors of the Company during the year ended 30 June 2023 and up to the date of this report are: Surname Davis Beckett Bainbridge Clement Hall Jager Layman Moore Richards Stokes Other Names Glenn Stuart Colin David (1) Philip James (2) Bruce Frederick William (3) Margaret Helen (4) Robert (5) Sally-Anne Georgina Peter Stanley Richard Joseph Ryan Kerry (6) Position Independent non-executive Chairman Independent non-executive Deputy Chairman Independent non-executive director Independent non-executive/Executive director Non-executive director/Alternate Independent non-executive director Independent non-executive director Independent non-executive director Non-executive director Alternate/Non-executive director (1) Retired on 16 November 2022. (2) Retired on 31 March 2023. (3) Appointed 8 May 2023 as a non-executive director. Appointed 9 August 2023 as Interim Chief Executive Officer and continues as an executive director. (4) Retired on 23 July 2023 and appointed Mr Stokes’ alternate on that date. (5) Retired on 16 November 2022. (6) Appointed a non-executive director on 23 July 2023. Prior to that date Mr Stokes was Ms Hall’s alternate. Directors’ interests in shares, options and rights The relevant interest of each director in the ordinary share capital of Beach at the date of this report is: Shares held in Beach Energy Limited Name G S Davis B F W Clement M H Hall (3) S G Layman P S Moore R J Richards (4) R K Stokes (5) (1) Held directly. Shares Rights 320,101 (2) – 17,068 (2) 45,000 (2) 44,200 (2) 488,053 (2) 150,000 (1) – – – – – – – (2) Held by entities in which a relevant interest is held. (3) Ms Hall was nominated as a director by Beach’s largest shareholder Seven Group Holdings Limited (SGH) and related corporations who collectively have a relevant interest in 30.02% of Beach shares. Ms Hall retired from the Board on 23 July 2023 and was appointed Mr Stokes’ alternate on that date. Ms Hall is the chief executive officer of SGH Energy. (4) Mr Richards was nominated as a director by SGH. He is the Chief Financial Officer of SGH. (5) Mr Stokes was an alternate director for Ms Hall until 23 July 2023 when he was appointed a director on that date. Mr Stokes was nominated by SGH and is Managing Director and Chief Executive Officer of SGH. Details of the qualifications, experience, special responsibilities and meeting attendance of each of the directors are set out later in the Directors’ Report. Director appointments and retirements During the financial year, the following changes to Board composition occurred: – C D Beckett and R J Jager retired on 16 November 2022. – P J Bainbridge retired on 31 March 2023. – B F W Clement was appointed a director of Beach on 8 May 2023. In the period between 30 June 2023 and up to the date of this report, the following changes to Board composition occurred: – M H Hall retired on 23 July 2023 and was appointed as an alternate director for Mr Stokes. – R K Stokes was appointed a director of Beach on 23 July 2023. – B F W Clement was appointed on 9 August 2023 as Interim Chief Executive Officer and continues as an executive director. As at 30 June 2023, the board comprises six directors. The approved maximum number of directors is nine. 38 Beach Energy Limited Annual Report 2023 Principal activities Beach Energy is an ASX listed, oil and gas, exploration and production company headquartered in Adelaide, South Australia. It has operated and non-operated, onshore and offshore, oil and gas production from five producing basins across Australia and New Zealand and is a key supplier to the Australian east coast gas market. Beach’s asset portfolio includes ownership interests in strategic oil and gas infrastructure and assets across Australia and New Zealand and continues to pursue growth opportunities which align with its strategy, satisfy strict capital allocation criteria, and demonstrate clear potential for shareholder value creation. Beach is focused on maintaining high health, safety and environmental standards. Operating and Financial Review A review of operations of Beach Energy during the financial year are set out on pages 20–33. Financial results from FY23 are summarised below: – Group profit attributable to equity holders of Beach was $400.8 million (FY22 $500.8 million). – Sales revenue was down 8% from FY22 to $1,616.9 million due to lower production volumes and US dollar oil and liquids prices, partly offset by higher third-party sales, favourable FX rates and gas and ethane prices. – Cost of sales were up 6% from FY22 to $1,055.6 million, mainly as a result of higher third-party purchases, depreciation and field operating costs, offset in part by lower royalties and favourable inventory movements. – A net profit after tax of $400.8 million was reported reflecting lower sales revenue, higher cost of sales and financing costs, partly offset by lower tax and other expenses. Key Results Operations Production Sales Capital expenditure Income Sales revenue Total revenue Cost of sales Gross profit Other income Other expenses Net profit after tax (NPAT) Underlying NPAT (1) Dividends paid Final dividend announced Basic EPS Underlying EPS (1) Cash flows Operating cash flow Investing cash flow Financial position Net assets Cash balance FY23 FY22 Change 19.5 20.7 (1,100.3) 1,616.9 1,646.4 (1,055.6) 590.8 10.3 (14.8) 400.8 384.8 3.00 2.00 17.58 16.88 21.8 22.4 (872.3) 1,749.1 1,771.4 (995.6) 775.8 12.0 (57.7) 500.8 504.3 2.00 1.00 21.97 22.12 928.6 (1,169.7) 1,223.2 (897.8) (11%) (7%) (26%) (8%) (7%) (6%) (24%) (14%) 74% (20%) (24%) 50% 100% (20%) (24%) (24%) (30%) As at 30 June 2023 As at 30 June 2022 Change 3,877.9 218.9 3,539.9 254.5 10% (14%) MMboe MMboe $m $m $m $m $m $m $m $m $m cps cps cps cps $m $m $m $m (1) Underlying results in the table above are categorised as non-IFRS financial information provided to assist readers to better understand the financial performance of the underlying operating business. They have not been subject to audit or review by Beach’s external auditors. Please refer to the table on page 41 for a reconciliation of this information to the financial report. 39 Directors’ Report Revenue Sales revenue of $1,616.9 million in FY23 was $132.2 million or 8% lower than FY22, driven by lower production volumes and US dollar oil and liquids prices, partly offset by higher third-party sales, favourable FX rates and stronger gas and ethane prices. Lower production volumes, a one-off non-cash impact for the change to timing of revenue recognition in the Cooper Basin and difference in sales mix reduced sales revenue by $208.3 million and lower US dollar oil and liquids prices decreased sales revenue by $140.6 million, with the average realised liquids price decreasing to US$84.23/boe, down from US$97.81/boe in FY22. These were partly offset by higher sales from third-party products which contributed an additional $91.2 million, favourable A$/US$ exchange rate in FY23 resulting in an increase of $67.8 million to sales revenue and favourable gas and ethane prices contributed $57.7 million with realised prices of $8.81/GJ. Sales Revenue Comparison ($m) 2,200 2,000 1,800 1,600 1,400 1,200 1,000 800 600 400 200 0 1,749.1 91.2 Third party sales 67.8 FX rates A$/US$ FY22 $0.726 FY23 $0.673 57.7 (140.6) (140.6) Gas/ethane prices A$/GJ FY22 $8.05 FY23 $8.81 Oil and liquids prices US$/boe FY22 $97.81 FY23 $84.23 (208.3) Volume/ mix 1,616.9 8% $132.2 million total decrease FY22 Average price A$78.22/boe FY23 Average price A$77.99/boe Gross Profit Gross profit for FY23 of $590.8 million (FY22 $775.8 million) was down 24%, driven by lower sales, higher third-party purchases, depreciation and field operating costs, partly offset by lower royalties and favourable inventory movement. The increase in cost of sales, up 6% from FY22 to $1,055.6 million, was driven by a $91.2 million increase in third-party purchases in addition to increases in depreciation of $35.4 million and field operating costs of $25.9 million. This was partly offset by lower royalties of $61.3 million and favourable inventory movements of $31.0 million. Gross Profit Comparison ($m) 775.8 35.6 Total operating costs 31.0 (35.4) (35.4) Inventory Depreciation (91.2) (91.2) Third party purchases Cost of Sales ($60.0) million 24% $185.0 million total decrease FY22 (125.0) (125.0) Sales and other revenue 590.8 FY23 900 800 700 600 500 400 300 200 100 0 40 Beach Energy Limited Annual Report 2023 Net Profit Result Other expenses of $14.8 million were $42.9 million lower than FY22 primarily due to the recognition of restoration expense of $29.5 million in FY22, relating to the increased restoration provisions for assets in abandonment phase in the Cooper Basin, and reversal of accrued acquisition costs of $16.8 million in FY23. This is partly offset by higher unwind on contract assets and liabilities of $6.5 million. The reported net profit after income tax of $400.8 million is $100.0 million lower than FY22, due to lower gross profit driven by lower sales revenue and higher cost of sales, and higher financing costs with a higher unwind of discount on restoration provisions, partly offset by lower income tax corresponding with lower profits and lower other expenses. By adjusting the FY23 profit to exclude reversal of accrued acquisition costs, Beach’s underlying net profit after tax is $384.8 million. Comparison of underlying profit Net profit after tax Adjusted for: Reversal of accrued acquisition costs Provision for legal costs related to shareholder class actions Tax impact of above changes Underlying net profit after tax(1) FY23 $ million 400.8 (16.8) – 0.8 384.8 FY22 $ million Movement from PCP $ million 500.8 (100.0) (20%) – 5.0 (1.5) 504.3 (16.8) (5.0) 2.3 (119.5) (24%) (1) Underlying results in this report are categorised as non-IFRS financial information provided to assist readers to better understand the financial performance of the underlying operating business. They have not been subject to audit or review by Beach’s external auditors. All of the items being adjusted pre-tax are separately identified within Note 3(b) to the financial statements. Underlying Net Profit After Tax Comparison ($m) 600 550 500 450 400 350 300 250 200 150 100 50 0 504.3 59.6 Tax 19.4 Other expenses and income (13.5) Net financing costs (185.0) Gross profit 24% $119.5 million total decrease FY22 384.8 FY23 41 Directors’ Report Financial Position Funding and Capital Management Assets Total assets increased by $792.8 million to $5,894.9 million during the period and cash balances decreased by $35.6 million to $218.9 million, primarily due to: – Cash outflow from investing activities of $1,169.7 million offset by, – Cash inflow from operations of $928.6 million, – Cash inflow from financing activities of $205.5 million. Inventory on hand at 30 June 2023 increased by $59.8 million following the current year one-off, non-cash change to the Cooper Basin revenue recognition point. Receivables increased by $15.6 million primarily driven by timing of liftings and joint venture cash calls, in addition to the recognition of a current tax asset $24.2 million. This is partly offset by a reduction in other assets of $88.3 million, driven by the decrease to prepayments for long lead items subsequently delivered and utilised for Waitsia Stage 2 and Thylacine well connections. Fixed assets, petroleum and exploration assets increased by $837.9 million due to capital expenditures of $1,089.4 million, increase to restoration estimates of $127.0 million, capitalisation of both borrowing cost of $13.2 million and depreciation of lease assets $9.0 million. Partly offset by depreciation and amortisation of $391.9 million and disposals of $9.8 million during the year. Liabilities Total liabilities increased by $454.8 million to $2,017.0 million primarily due to an increase in debt drawn of $296.0 million, provisions of $118.2 million and deferred tax liabilities of $94.6 million, partly offset by a decrease to current tax liabilities of $36.2 million and lease liabilities of $7.8 million. Equity Total equity increased by $338.0 million, primarily due to a net profit after tax of $400.8 million, partly offset by dividends paid during the period of $68.4 million. Dividends During the financial year, the Company paid a FY22 fully franked final dividend of 1.0 cent per share as well as an interim FY23 fully franked dividend of 2.0 cents per share. The Company will also pay a FY23 fully franked final dividend of 2.0 cents per share from the profit distribution reserve. State of affairs A review of operations of Beach Energy during the financial year on pages 20–33 sets out a number of matters that have had a significant effect on the state of affairs of the group. Other than those matters, there were no significant changes in the state of affairs of the group during the financial year. As at 30 June 2023, Beach held cash and cash equivalents of $218.9 million. Beach currently has senior secured facilities in place for $675 million, comprised of a three year $250 million revolving syndicated loan facility maturing September 2024 (Facility A), a five year $350 million revolving syndicated loan facility maturing September 2026 (Facility B) and three year $75 million bilateral Contingent Instrument facilities (CI Facilities) with a maturity date of September 2024. As at 30 June 2023, $385 million of loan facilities were drawn and $50 million of instruments issued under the CI Facilities. Material Business Risks Beach recognises that the management of risk is a critical component in Beach achieving its purpose of sustainably delivering energy for communities. The Company has a framework to identify, understand, manage and report risks. As specified in its Board Charter, the Board has responsibility for overseeing Beach’s risk management framework and monitoring its material business risks with a separate Risk, Corporate Governance and Sustainability Committee also established to assist the Board in ensuring there is an appropriate corporate entity risk management framework and that the process identifies business, operational, financial and regulatory risks and mitigation measures. Given the nature of Beach’s operations, there are many factors that could impact Beach’s operations and results. The material business risks that could have an adverse impact on Beach’s financial prospects or performance include economic risks, operational risks, social licence- to-operate and health, safety and environmental risks. A description of the nature of the risks and how such risks are managed is set out below. This list is neither exhaustive nor in order of importance. Economic risks Exposure to oil and gas prices Both the domestic gas market and the global oil market experience fluctuations in supply and demand, resulting in corresponding price variations. A decline in the price of oil and gas may have a material adverse effect on Beach’s financial performance. Historically, international crude oil prices and domestic gas prices have been volatile. A sustained period of low or declining crude oil prices and/or gas prices and/or further unfavourable regulatory interventions could adversely affect Beach’s operations, financial position and ability to finance developments. Beach uses a structured framework for capital allocation decisions. The process provides rigorous value and risk assessment against a broad range of business metrics and stringent hurdles to maximise return on capital. Declines in the price of oil and gas and continuing price volatility may also lead to revisions of the medium and longer term price assumptions for future production, which, in turn, may lead to a revision of the carrying value of some of Beach’s assets. 42 Beach Energy Limited Annual Report 2023 The valuation of oil and gas assets is affected by a number of assumptions, including the quantity of reserves and resources booked in relation to these oil and gas assets and their expected cash flows. An extended or substantial decline in oil and/or gas prices or demand, or an expectation of such a decline, may reduce the expected cash flows and/or quantity of reserves and resources booked in relation to the associated oil and gas assets, which may lead to a reduction in the valuation of these assets. If the valuation of an oil and gas asset is below its carrying value, a non-cash impairment adjustment to reduce the historical book value of these assets will be made with a subsequent reduction in the reported net profit in the same reporting period. Contract and Counterparty Risk A dispute, or a breakdown in the relationship, between Beach and its JVPs, suppliers or customers, a failure to reach a suitable arrangement with a particular JVP, supplier or customer, the failure of a JVP, supplier or customer to pay or otherwise satisfy its contractual obligations (including as a result of insolvency, financial stress or the impacts of COVID-19), lower than expected customer lifting on existing gas sales agreements that are subject to high degrees of customer flexibility and customer exclusivity could have an adverse effect on the reputation and/or the financial performance of Beach. Foreign exchange and commodity price risk The Group’s functional currency is Australian dollars. Beach’s exposure to foreign currency risk arises from commercial transactions, expenditure and valuation of asset and liabilities that are not denominated in the entities functional currency, principally US dollars and New Zealand dollars. To satisfy payment obligations in jurisdictions where the Australian dollar is not accepted, Beach converts funds as payments become due. Funds received in foreign currencies that are surplus to forecast needs are required to be converted to Australian dollars at the prevailing exchange rate. Beach is exposed to commodity price fluctuations through the sale of petroleum productions and other oil-linked contracts. The Company may use derivative financial instruments to economically hedge risk exposures, such as foreign exchange forward, foreign currency swap, foreign currency option contracts and commodity price swap and option contracts. Ability to access funding Beach operates in the oil and gas industry, undertaking significant exploration, development, production, processing and transportation activities. To fund this activity, the Group relies on cash flows from operating activities and access to debt and equity markets. The ability to access funding may be negatively impacted by factors such as the Group’s capital structure, financial markets volatility and the ESG concerns of lenders and investors. This may result in postponement of or reduction in planned capital expenditure, relinquishment of rights in relation to assets, an inability to take advantage of opportunities or otherwise respond to market conditions. Any of these outcomes could have a material adverse effect on the Group’s financial position, its ability to expand its business and/or maintain its operations at current levels. Beach manages financial risks through a central treasury function, which operates under a Board approved financial risk management policy covering areas such as liquidity, debt management, interest rate risk, foreign exchange risk, commodity risk and counterparty credit risk. The policy sets out the organisational structure, clear delegations and reporting obligations required for the prudent management of risk. The annual capital and operating budgeting processes approved by the Board ensure appropriate allocation of resources. Operational risks Joint Venture Operations Beach participates in a number of joint ventures for its business activities. This is a common form of business arrangement designed to share risk and other costs. Under certain joint venture operating agreements, Beach may not control the approval of work programs and budgets and a JVP may vote to participate in certain activities without the approval of Beach. Beach may also not control the quality or timeliness of delivery of agreed works. As a result, Beach may experience a dilution of its interest or may not gain the benefit of the activity, except at a significant cost penalty later in time. Failure to reach agreement on exploration, development and production activities may have a material impact on Beach’s business. Failure of Beach’s JVPs to meet financial and other obligations may have an adverse impact on Beach’s business. Beach works closely with its JVPs to minimise joint venture misalignment. Material change to reserves and resources The estimated quantities of reserves and resources are based upon interpretations of geological, geophysical and engineering models and assessment of the technical feasibility and commercial viability of production. Estimates that are valid at a certain point in time may alter significantly or become uncertain when new reservoir information becomes available through field production, additional drilling or technical analysis. As reserves and resources estimates change, development and production plans may be altered in a way that may adversely affect Beach’s operations and financial results. Beach prepares its reserves and resources estimates in accordance with the 2018 update to the Petroleum Resources Management System sponsored by the Society of Petroleum Engineers, World Petroleum Council, American Association of Petroleum Geologists, Society of Petroleum Evaluation Engineers, Society of Exploration Geoscientists, Society of Petrophysicists and Well Log Analysts and the European Association of Geoscientists & Engineers (SPE-PRMS). The estimates are subject to periodic independent review or audit. 43 Directors’ Report Abandonment and restoration liabilities Beach holds long term operating assets which require decommissioning at the end of their operational life. This provision is material in value and subject to changes in legislative requirements. Failure to adequately estimate or provide for these deferred expenses, or if a restoration liability arises earlier than expected it may impact Beach’s business. Exploration and development Success in oil and gas production is key and in the normal course of business Beach depends on the following factors: successful exploration, establishment of commercial oil and gas reserves, finding commercial solutions for exploitation of reserves, ability to design and construct efficient production, gathering and processing facilities, efficient transportation and marketing of hydrocarbons and sound management of operations. Oil and gas exploration is a speculative endeavour and the nature of the business carries a degree of risk associated with failure to find hydrocarbons in commercial quantities or at all. Beach utilises well-established prospect evaluation and ranking methodology to manage exploration risks. Major Project Delivery Beach is focused on creating shareholder value through investments in various oil and gas projects, as well as investments in decarbonisation initiatives. However, with any significant capital project, there is a risk of failure or incomplete achievement of project objectives, which could result in lower investment returns than initially anticipated. These risks could emerge from various factors, including challenges in obtaining necessary regulatory approvals within expected timelines, obstacles in securing land access (including navigating native title agreements), procurement issues resulting from delays in equipment fabrication or constraints in global supply chains, labour shortages, inflationary pressures, failure to effectively define or meet project scope, budget, and definition, deficiencies in project design and quality, concerns regarding process safety, failures in cost control and delivery schedule management, limitations in available resources and suboptimal decision-making. Beach has implemented a comprehensive project development process supported by governance, risk management and reporting. Senior management and the Board actively review the progress and performance of significant projects to ensure proper oversight and decision making. Production risks Any oil or gas project, covering on and/or off-shore activity, may be exposed to production decrease or stoppage, which may be the result of facility shut-downs, mechanical or technical failure, project delays, climatic events and other unforeseeable events. A significant failure to maintain production could result in Beach lowering production forecasts, loss of revenue and additional operational costs to bring production back online. There may be occasions where loss of production may incur significant capital expenditure, resulting in the requirement for Beach to seek additional funding, through equity or debt. Beach’s approach to facility design, process safety and integrity management is critical to mitigating production risks. Beach and its JVPs may face disruptions as a result of the restrictions on the movement and supply of personnel and products due to external influences such as geopolitical unrest or conflict. A significant failure to meet production and/or project targets could compromise Beach's production and sales deliverability obligations, impact operating cash flows through loss of revenue and/or from incurring additional costs needed to reinstate production to required levels. Cyber Risk The integrity, availability and confidentiality of data within Beach’s information and operational technology systems may be subject to intentional or unintentional disruption (for example, from a cyber security attack). Beach continues to invest in robust processes and technology, supported by specialist cyber security skills to prevent, detect, respond and recover from such attacks should one occur. This risk has escalated as a result of the increased global cyber threat across the economy, particularly with regard to ransomware. Beach has invested in further measures that align with the Australian Energy Sector Cyber Security Framework. In addition, we test existing controls through regular penetration testing, phishing simulations and cyber exercises. The Board and its committee’s consider cyber risks regularly, commensurate with the evolving nature of this risk and the level of internal activity. People and Capability The industry we operate in faces challenges in attracting and retaining personnel with specialised skills and expertise. The inability to attract and retain such individuals could potentially disrupt business continuity through the loss of critical capability. To address this risk, we have implemented employment arrangements that are specifically designed to secure and retain key personnel. 44 Beach Energy Limited Annual Report 2023 Social licence to operate risks Regulatory risk Changes in government policy (such as in relation to taxation, environmental protection, competition and pricing regulation and the methodologies permitted to be used in oil and gas exploration and production activity such as produced water disposal) or statutory changes may affect Beach’s business operations and its financial position. A change in government regime may significantly result in changes to fiscal, monetary, property rights and other issues which may result in a material adverse impact on Beach’s business and its operations. Companies in the oil and gas industry may also be required to pay direct and indirect taxes, royalties and other imposts in addition to normal company taxes. Beach currently has operations or interests in Australia and New Zealand. Accordingly its profitability may be affected by changes in government taxation and royalty policies or in the interpretation or application of such policies in each of these jurisdictions. Beach monitors changes in relevant regulations and engages with regulators and governments to ensure policy and law changes are appropriately influenced and understood. Disputes and litigation The nature of the operations of Beach means it may be involved in litigation or disputes from a range of sources, including contractual disputes, breach of laws, lawsuits or personal claims. Beach maintains an experienced in-house legal team and keeps abreast of claims, changes to legislation and regulatory requirements. Permitting risk All petroleum licences held by Beach are subject to the granting and approval of relevant government bodies and ongoing compliance with licence terms and conditions. Tenure management processes and standard operating procedures are utilised to minimise the risk of losing tenure. Land access, cultural heritage Native Title and community stakeholders Beach is required to obtain the consent of owners and occupiers of land within its licence areas. Compensation may be required to be paid to the owners and occupiers of land in order to carry out exploration and development activities. Beach operates in a number of areas within Australia that are or may become subject to claims or applications for native title determinations or other third party access. Native title claims have the potential to introduce delays in the granting of petroleum and other licences and, consequently, may have an effect on the timing and cost of exploration, development and production. Native or indigenous title and land rights may also apply or be implemented in other jurisdictions in which Beach operates outside of Australia, including New Zealand. The oil and gas industry is also subject to interest from a wide range of stakeholders from the broader community which may be opposed to the role of the industry. Beach’s standard operating procedures and stakeholder engagement processes are used to manage land access, cultural heritage, native title and community stakeholder risks. Health, safety and environmental risks The business of exploration, development, production and transportation of hydrocarbons involves a variety of risks which may impact the health and safety of personnel, the community and the environment. Oil and gas production and transportation can be impacted by natural disasters, operational error or other occurrences which can result in hydrocarbon leaks or spills, equipment failure and loss of well control. Potential failure to manage these risks could result in injury or loss of life, damage or destruction of wells, production facilities, pipelines and other property, damage to the environment, legal liability and damage to Beach’s reputation. Losses and liabilities arising from such events could significantly reduce revenues or increase costs and have a material adverse effect on the operations and/or financial conditions of Beach. Beach employs an Operations Excellence Management System to identify and manage risks in this area. Insurance policies, standard operating procedures, contractor management processes and facility design and integrity management systems, amongst other things, are important elements of the system that supports mitigation of these risks. Beach seeks to maintain appropriate policies of insurance consistent with those customarily carried by organisations in the energy sector. Any future increase in the cost of such insurance policies, or an inability to fully renew or claim against insurance policies as a result of the current economic environment (for example, due to a deterioration in an insurers ability to honour claims), could adversely affect Beach’s business, financial position and operational results. 45 Directors’ Report Pandemic risk Large scale pandemic outbreak of a communicable disease such as COVID-19 has the potential to affect personnel, production and delivery of projects. The Company employs its crisis and emergency management plans, health emergency plans and business continuity plans to manage this risk including ongoing monitoring and response to government directions and advice. This enables the Company to take active steps to manage risks to the Company’s staff and stakeholders and to mitigate risks to production and progress of growth projects. Climate change Beach is likely to be subject to increasing regulations and costs associated with climate change and management of carbon emissions. Strategic, regulatory and operational risks and opportunities associated with climate change and the energy transition are incorporated into Company policy, strategy and risk management processes and practices. The Company actively monitors current and potential areas of climate change and energy transition risk and takes actions to prevent and/or mitigate impacts on its objectives and activities including setting of targets to reduce carbon emissions. Reduction of waste and emissions is an integral part of delivery of cost efficiencies and forms part of the Company’s routine operations. Forward looking statements This report contains forward-looking statements, including statements of current intention, opinion and predictions regarding the Company’s present and future operations, possible future events and future financial prospects. While these statements reflect expectations at the date of this report, they are, by their nature, not certain and are susceptible to change. Beach makes no representation, assurance or guarantee as to the accuracy or likelihood of fulfilling of such forward looking statements (whether expressed or implied), and except as required by applicable law or the ASX Listing Rules, disclaims any obligation or undertaking to publicly update such forward-looking statements. Material prejudice As permitted by sections 299(3) and 299A(3) of the Corporations Act 2001, Beach has omitted some information from the above Operating and Financial Review in relation to the Company’s business strategy, future prospects and likely developments in operations and the expected results of those operations in future financial years on the basis that such information, if disclosed, would be likely to result in unreasonable prejudice (for example, because the information is premature, commercially sensitive, confidential or could give a third party a commercial advantage). The omitted information typically relates to internal budgets, forecasts and estimates, details of the business strategy, and contractual pricing. Environmental regulations and performance statement Beach participates in projects and production activities that are subject to the relevant exploration and development licences prescribed by government. These licences specify the environmental regulations applicable to the exploration, construction and operation of petroleum activities as appropriate. For licences operated by other companies, Beach monitors the performance of these companies against these regulations. There have been no known significant breaches of the environmental obligations of Beach's operated contracts or licences during the financial year. Beach reports under the National Greenhouse and Energy Reporting Act for its Australian operations and the Climate Change Response Act 2002 for its New Zealand operations. Dividends paid or recommended Since the end of the financial year the directors have resolved to pay a fully franked dividend of 2.0 cents per share on 3 October 2023. The record date for entitlement to this dividend is 5 September 2023. The financial impact of this dividend, amounting to $45.6 million has not been recognised in the Financial Statements for the year ended 30 June 2023 and will be recognised in subsequent Financial Statements. The details in relation to dividends paid during the reporting period are set out below: Dividend FY22 Final FY23 Interim Record Date Date of payment Cents per share Total Dividends 31 August 2022 28 February 2023 30 September 2022 31 March 2023 1.0 2.0 $22.8 million $45.6 million For Australian income tax purposes, all dividends were fully franked and were not sourced from foreign income. 46 Beach Energy Limited Annual Report 2023 Share options and rights Beach does not have any options on issue at the end of financial year and has not issued any during FY23. Share rights holders do not have any right to participate in any issue of shares or other interests in the Company or any other entity. There have been no unissued shares or interests under option of any controlled entity within the Group during or since the reporting date. For details of performance rights issued to executives as remuneration, refer to the Remuneration Report. During the financial year, the following movement in share rights to acquire fully paid shares occurred: Executive Performance Rights Throughout FY23, Beach issued the following Short Term Incentive (STI) and Long Term Incentive (LTI) unlisted performance rights under the Executive Incentive Plan (EIP): 168,598 LTI on 12 October 2022; 356,293 STI on 21 November 2022; 2,265,837 LTI on 1 December 2022; and 2,331,378 Retention Rights on 2 February 2023. With regards to LTI rights on issue: – 168,598 performance rights, expire on 30 November 2026, are exercisable for nil consideration and are not exercisable before 1 December 2024; and – 2,265,837 performance rights, expire on 30 November 2027, are exercisable for nil consideration and are not exercisable before 1 December 2025. Further details can be found in Table 7 of the Remuneration report. Issued 14 December 2020, 31 May 2021 and 30 September 2021 1,616,970 Rights 2019 LTI unlisted rights Issued 19 December 2019 and 14 December 2021 2019 STI unlisted rights Issued 25 November 2020 2020 LTI unlisted rights 2021 LTI unlisted rights Issued 31 December 2021, 31 March 2022, 30 June 2022 and 12 October 2022 2021 STI unlisted rights Issued 21 November 2022 2022 Retention unlisted rights Issued 2 February 2023 2022 LTI unlisted rights Issued 1 December 2022 Total Balance at beginning of financial year Issued during the financial year Vested/ exercised during the financial year Expired/ lapsed during the financial year Balance at end of financial year 804,222 73,164 – – – 3,135,410 168,598 – – – 356,293 2,331,378 2,265,837 – (804,222) (73,164) – – – – – – – – (594,512) 1,022,458 (675,053) 2,628,955 – 356,293 (175,953) 2,155,425 (85,197) 2,180,640 5,629,766 5,122,106 (73,164) (2,334,937) 8,343,771 47 Directors’ Report Employee share plan An employee share plan (Plan) was approved by shareholders in November 2019. Under the terms of the Plan, employees who buy shares under the Plan will have those shares matched by Beach, provided any relevant conditions determined by the Board are satisfied. Eligible Employees are employees of the Group, other than a non-executive director and any other person determined by the Board as ineligible to participate in the Plan. The Board has the discretion to set an annual limit on the value of shares that participants may purchase under the Plan, not exceeding $5,000. Purchased Shares have been acquired periodically at the prevailing market price. Participants pay for their Purchased Shares using their own funds which may include salary sacrifice. To receive Matched Shares, a participant must satisfy the conditions determined by the Board at the time of the invitation, including remaining an employee throughout the three year vesting period. Full terms can be found in the Notice of 2018 Annual General Meeting released on 19 October 2018. Rights FY20 employee share plan (1) Issued up to 30 June 2020 FY21 employee share plan (2) Issued up to 30 June 2021 FY22 employee share plan (3) Issued up to 30 June 2022 FY23 employee share plan (4) Issued up to 30 June 2023 Total Balance at beginning of financial year Issued during the financial year Vested/ exercised during the financial year Expired/ lapsed during the financial year Balance at end of financial year 433,886 698,587 670,914 – – – – 575,701 (433,886) – – – – – (65,359) 633,228 (52,514) 618,400 (21,586) 554,115 1,803,387 575,701 (433,886) (139,459) 1,805,743 (1) 3-year restriction period ended 1 July 2022. (2) 3-year restriction period end on the first practicable date after 30 June 2023. (3) 3-year restriction period end on the first practicable date after 30 June 2024. (4) 3-year restriction period end on the first practicable date after 30 June 2025. Information on Directors The names of the directors of Beach who held office during the financial year and at the date of this report are: Glenn Stuart Davis Independent non-executive Chairman – LLB, BEc, FAICD Experience and expertise Bruce Frederick William Clement Executive Director and Interim Chief Executive Officer – BEng (Civil) Hons, BSc, MBA Mr Davis has practiced as a solicitor in corporate and risk throughout Australia for over 35 years initially in a national firm and then a firm he founded. He has expertise and experience in the execution of large transactions, risk management and in corporate activity regulated by the Corporations Act and ASX Limited. Mr Davis has worked in the oil and gas industry as an advisor and director for over 25 years. Current and former listed company directorships in the last 3 years Mr Davis is currently a director of ASX listed company iTech Minerals Ltd (ITM) (since 2021), Adrad Holdings Pty Ltd (since January 2022) and SkyCity Entertainment Group Limited (since September 2022). Responsibilities His special responsibilities include Chairmanship of the Board and membership of the Remuneration and Nomination Committee. Date of appointment Mr Davis joined Beach on 6 July 2007 as a non-executive director. He was appointed non-executive Deputy Chairman in June 2009 and Chairman in November 2012. He was last re-elected to the Board on 25 November 2020. Experience and expertise Mr Clement has over 40 years of domestic and international energy industry experience. He has managed oil and gas exploration, development and production operations in Australia and Asia and has delivered key projects across these regions and in the UK and US. He also has extensive experience and knowledge of the Perth Basin, including overseeing the discovery of the Waitsia gas field as Managing Director of AWE. Mr Clement previously held engineering, senior management, and board positions with several companies including Santos, Norwest Energy, AWE, ExxonMobil and Roc Oil. Current and former listed company directorships in the last 3 years Mr Clement is currently a non-executive director of Horizon Oil (since 2020). Date of appointment Mr Clement was appointed to the Board on 8 May 2023 and pursuant to the constitution will retire at the 2023 Annual General Meeting being eligible to seek re-election. Mr Clement was appointed on 9 August 2023 as Interim Chief Executive Officer and continues as an executive director. 48 Beach Energy Limited Annual Report 2023 Sally-Anne Layman Independent non-executive director – B Eng (Mining) Hon, B Com, CPA, MAICD Richard Joseph Richards Non-executive director – BComs/Law (Hons), LLM, MAppFin, CA, Admitted Solicitor Experience and expertise Experience and expertise Ms Layman is a company director with diverse international experience in the resources sector and financial markets. Previously, Ms Layman held a range of senior positions with Macquarie Group Limited, including as Division Director and Joint Head of the Perth office of the Metals, Mining & Agriculture Division. Prior to moving into finance, Ms Layman undertook various roles with resource companies including Mount Isa Mines, Great Central Mines and Normandy Yandal. Ms Layman holds a WA First Class Mine Manager’s Certificate of Competency, a Bachelor of Engineering (Mining) Hon from Curtin University and a Bachelor of Commerce from the University of Southern Queensland. Ms Layman is a Certified Practicing Accountant and is a member of CPA Australia Ltd and the Australian Institute of Company Directors. Mr Richard Richards has been Chief Financial Officer of Seven Group Holdings Limited (SGH) since October 2013. He is a Director of SGH Energy and is a Director and Chair of the Audit and Risk Committee of WesTrac Pty Limited and Coates Hire Pty Limited. He is a Director of Boral Limited and is a member of their Audit and Risk and Safety Committees and he is also a Director of Flagship Property Holdings. Mr Richards joined SGH from the diverse industrial group, Downer EDI, where he was Deputy Chief Financial Officer responsible for group finance across the company for three years. Prior to joining Downer EDI, Mr Richards was CFO for the Family Operations of LFG, the private investment and philanthropic vehicle of the Lowy Family for two years. Prior to that, Richard held senior finance roles at Qantas for over 10 years. Current and former listed company directorships in the last 3 years Ms Layman is on the board of Newcrest Mining Ltd (since September 2020), Imdex Ltd (since February 2017) and Pilbara Minerals Ltd (since April 2018) and was previously on the board of Perseus Mining Ltd (from September 2017 until October 2020). Responsibilities Her special responsibilities include Chair of the Audit Committee and membership of the Remuneration and Nomination Committee and Risk, Corporate Governance and Sustainability Committee. Date of appointment Ms Layman was appointed to the Board on 25 February 2019 and last re-elected to the Board on 16 November 2022. Peter Stanley Moore Independent non-executive director – PhD, BSc (Hons), MBA, GAICD Experience and expertise Dr Moore has over forty years of oil and gas industry experience. His career commenced at the Geological Survey of Western Australia, with subsequent appointments at Delhi Petroleum Pty Ltd, Esso Australia, ExxonMobil and Woodside. Dr Moore joined Woodside as Geological Manager in 1998 and progressed through the roles of Head of Evaluation, Exploration Manager Gulf of Mexico, Manager Geoscience Technology Organisation and Vice President Exploration Australia. From 2009 to 2013, Dr Moore led Woodside’s global exploration efforts as Executive Vice President Exploration. In this capacity, he was a member of Woodside’s Executive Committee and Opportunities Management Committee, a leader of its Crisis Management Team, Head of the Geoscience function and a director of ten subsidiary companies. From 2014 to 2018, Dr Moore was a Professor and Executive Director of Strategic Engagement at Curtin University’s Business School. He has his own consulting company, Norris Strategic Investments Pty Ltd. Current and former listed company directorships in the last 3 years Dr Moore is currently a non-executive director of Carnarvon Petroleum Ltd (since 2015). Responsibilities His special responsibilities include Chairmanship of the Remuneration and Nomination Committee and the Risk, Corporate Governance and Sustainability Committee and membership of the Audit Committee. Date of appointment Dr Moore was appointed by the Board on 1 July 2017 and last re-elected to the Board on 16 November 2022. Mr Richards is a former Director and the Chair of Audit and Risk Management Committee of KU – established in 1895 as the Kindergarten Union of New South Wales, KU is one of the most respected childcare providers in Australia. He was also a member of the Marcia Burgess Foundation Committee. Current and former listed company directorships in the last 3 years Boral Limited during October 2021 and was reappointed during August 2022. Responsibilities His special responsibilities include membership of the Audit Committee and Risk, Corporate Governance and Sustainability Committee. Date of appointment Mr Richards was appointed to the Board on 4 February 2017 and was last re-elected to the board on 25 November 2020. Ryan Kerry Stokes, AO Non-executive director from 23 July 2023 – BComm, FAIM (alternate for Margaret Hall up to 23 July 2023) Experience and expertise Mr Stokes is the Managing Director and Chief Executive Officer of SGH, a leading Australian diversified operating and investment group with market leading businesses and investments in industrial services, media and energy. This includes Westrac Pty Limited, Coates Hire Pty Limited, Boral Limited (72.6%), Seven West Media Limited (39%), and Beach (30%). Mr Stokes is Chair of WesTrac, Coates, Boral, and a non-executive director of Seven West Media. Mr Stokes is Chief Executive Officer of Australian Capital Equity (ACE). ACE is a private company with its primary investment being an interest in SGH. Mr Stokes is Chairman of the National Gallery of Australia and is an Officer of the Order of Australia. Current and former listed company directorships in the last 3 years Mr Stokes is an executive director of SGH (since 2010) and a non-executive director of Seven West Media (since 2012) and Boral Limited (since September 2020). Responsibilities His special responsibilities include membership of the Remuneration and Nomination Committee. Date of appointment Mr Stokes was a non-executive director from 20 July 2016 to November 2021, an alternate director for Margaret Hall from 1 December 2021 to 23 July 2023, and re-appointed to the Board on 23 July 2023. 49 Directors’ Report The details of the directors of Beach who held office during the financial year and are no longer on the Board are: Philip James Bainbridge Independent non-executive director – BSc (Hons) Mechanical Engineering, MAICD Experience and expertise Mr Bainbridge has extensive industry experience having worked for the BP Group for 23 years in a range of petroleum engineering, development, commercial and senior management roles in the UK, Australia and USA. From 2006, he worked at Oil Search, initially as Chief Operating Officer, then Executive General Manager LNG, responsible for all aspects of Oil Search’s interests in the $19 billion PNG LNG project, then EGM Growth responsible for gas growth and exploration. Current and former listed company directorships in the last 3 years Mr Bainbridge is currently a non-executive director of Newcrest Mining Ltd (since April 2021) and SIMS Limited (since September 2022). Responsibilities His special responsibilities included membership of the Audit Committee and the Risk, Corporate Governance and Sustainability Committee. Date of appointment/resignation Mr Bainbridge was appointed to the Board on 1 March 2016 and was last re-elected to the Board on 26 November 2019. Mr Bainbridge retired from the Board on 31 March 2023. Colin David Beckett, AO Independent non-executive Deputy Chairman – FIEA, MICE, GAICD Experience and expertise Mr Beckett is an experienced non-executive director and previously held senior executive positions in Australia with Chevron, Mobil, and BP. His experience in engineering design, project management, commercial negotiations and gas marketing provides him with a diverse and complementary set of skills relevant to the oil and gas industry. Mr Beckett read engineering at Cambridge University and has a Master of Arts. He was awarded an honorary doctorate from Curtin University in 2019. He was previously a fellow of the Australian Institute of Engineers. He is a graduate member of the Institute of Company Directors. He is currently Chair of Western Power. He was the Chancellor of Curtin University until end 2018. He is a past Chairman of Perth Airport Pty Ltd and past Chairman of the Australian Petroleum Producers and Explorers Association (APPEA). Current and former listed company directorships in the last 3 years Nil. Responsibilities His special responsibilities included Chairmanship of the Remuneration and Nomination Committee. Date of appointment Mr Beckett was appointed to the Board on 2 April 2015 and last re-elected to the Board on 26 November 2019. Mr Beckett retired from the Board on 16 November 2022. 50 Robert Jager Independent Non-executive Director Experience and expertise Mr Jager has extensive executive, industry and board experience following a career of more than 40 years with Shell in a variety of executive roles, most recently as Vice President Prelude in Perth. Prior to that, Mr Jager served as Vice President and Country Chair for Shell’s New Zealand business. Mr Jager has most recently been an independent non-executive director of Air New Zealand, serving for nearly nine years, including as chair of the Board health, safety and security committee. In 2018, Mr Jager was awarded an Officer of New Zealand Order of Merit (ONZM) for his services to business and health and safety. During his career Mr Jager chaired the Petroleum Exploration and Production Association of NZ as well as the Business Leaders Health and Safety Forum. Current and former listed company directorships in the last 3 years Mr Jager was formerly a director of Air New Zealand Limited until October 2021. Responsibilities His special responsibilities included membership of the Risk, Corporate Governance & Sustainability Committee. Date of appointment Mr Jager was appointed to the Board on 14 December 2021 and retired on 16 November 2022. Margaret Helen Hall Non-executive director – B.Eng (Met) Hons, MIEAust, GAICD, SPE Experience and expertise Ms Hall is the chief executive officer of Seven Group Holdings Energy, a subsidiary of Seven Group Holdings Limited. Ms Hall has over 31 years of experience in the oil and gas industry having worked at both super-major and independent companies. From 2011 to 2014 Ms Hall held senior management roles in Nexus Energy with responsibilities covering Development, Production Operations, Engineering, Exploration, Health, Safety and Environment. This was preceded by 19 years with ExxonMobil in Australia, across production and development in the Victorian Gippsland Basin and joint ventures across Australia. Current and former listed company directorships in the last 3 years Nil. Responsibilities Her special responsibilities include membership of the Risk, Corporate Governance and Sustainability Committee. Date of appointment Ms Hall was appointed to the Board on 10 November 2021. She retired from the Board on 23 July 2023 and was appointed an alternate to Mr Ryan Stokes on that date. Beach Energy Limited Annual Report 2023 Directors’ meetings The number of Directors’ meetings and meetings of Committees of Directors held during the financial year and the number of meetings attended by each of the directors is set out below: Directors’ Meetings Audit Committee Meetings Remuneration and Nomination Committee Meetings Risk, Corporate Governance and Sustainability Committee Meetings Held(1) Attended Held(1) Attended Held(1) Attended Held(1) Attended 22 9 18 2 21 (2) 9 22 22 21 (2) – 22 8 18 2 21 4 22 22 21 – – – 5 – – – 6 1 6 – – – 5 – – – 6 1 6 – 7 4 – – – – 2 7 7 – 7 4 – – – – 2 7 7 – – – 8 – 9 3 1 9 – – – – 8 – 9 3 1 9 – – Name G S Davis C D Beckett P J Bainbridge B F W Clement M H Hall R Jager S G Layman P S Moore R J Richards R K Stokes (3) (1) Number of Meetings held during the time that the director was appointed to the Board or committee. (2) Ms Hall and Mr Richards recused themselves from one meeting held during the year on account of the subject matter. (3) Mr Stokes was not required to attend any meetings during FY23 for Ms Hall as an alternate director. Board Committees Following further changes after the end of the financial year, the Chairmanship and current membership of each of the board committees at the date of this report are as follows: Committee Audit Remuneration and Nomination Risk, Corporate Governance & Sustainability Chairman S G Layman P S Moore P S Moore Indemnity of Directors and Officers Members P Moore, R J Richards G S Davis, S G Layman, R K Stokes S G Layman, R J Richards Beach has arranged directors’ and officers’ liability insurance policies that cover all the directors and officers of Beach and its controlled entities. The terms of the policies prohibit disclosure of details of the amount of the insurance cover, the nature thereof and the premium paid. Indemnification of auditor To the extent permitted by law, the Company has agreed to indemnify its auditor, 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). No payment has been made to indemnify Ernst & Young during the financial year and up to the date of this report. 51 Directors’ Report Joint Company Secretary Rounding off of amounts Susan Jones General Counsel/Joint Company Secretary – LLB (Hons) Ms Jones joined Beach in February 2021 and was appointed General Counsel in August 2021 and Company Secretary on 23 September 2022. She has over 25 years experience having worked in Australia, USA, UK and northern Africa in legal and non-legal roles. Her legal experience covers all aspects of legal operations, M&A, project finance, PSC negotiations, commodity sales and compliance. She has also held senior commercial and asset management roles. Previous employers include Total, Woodside, BHP and Ophir. In addition to her in-house experience, she has worked at King Wood Mallesons (Australia) and Sidleys (New York). Ms Jones is originally from South Australia and holds a first class honours LLB. In addition to being admitted to practice law in Australia she is admitted to practice in New York. David Lim Joint Company Secretary – LLB, B.Ec Mr Lim was appointed Company Secretary of Beach Energy on 10 February 2023. Mr Lim is a highly experienced lawyer and company secretary with previous ASX listed and public sector appointments. He is experienced in acquisitions and divestments, infrastructure projects, capital markets and funding transactions, commercial property, corporate governance, ASX requirements, executive contracts and remuneration, safety and risk management. Non-audit services Beach may decide to employ the external auditor on assignments additional to their statutory audit duties where the auditor’s expertise and experience with Beach are important. The Board has considered the position and is satisfied that the provision of the non-audit services is compatible with the general standard of independence for auditors imposed by the Corporations Act 2001. The directors are satisfied that the provision of non-audit services by the auditor as set out below, did not compromise the audit independence requirement of the Corporations Act 2001 for the following reasons: – All non-audit services have been reviewed by the Audit Committee to ensure they do not impact the impartiality and objectivity of the auditor. – None of the services undermine the general principle relating to auditor independence as set out in APES 110 Code – Code of Ethics for Professional Accountants, including reviewing or auditing the auditor’s own work, acting in a management or a decision making capacity for Beach, acting as advocate for Beach or jointly sharing economic risk and reward. Details of the amounts paid or payable to the external auditors, Ernst & Young, for audit and non-audit services provided during the year are set out at Note 27 to the financial statements. Beach is an entity to which ASIC Corporations (Rounding in Financial/Directors’ Reports) Instrument 2016/191 issued by the Australian Securities and Investments Commission applies relating to the rounding off of amounts. Accordingly, amounts in the directors’ report and the financial statements have been rounded to the nearest hundred thousand dollars, unless shown otherwise. Proceedings on behalf of Beach No person has applied to the Court under Section 237 of the Corporations Act 2001 for leave to bring proceedings on behalf of Beach, or to intervene in any proceedings to which Beach is a party, for the purpose of taking responsibility on behalf of Beach for all or part of those proceedings. No proceedings have been brought or intervened in on behalf of Beach with leave of the Court under Section 237 of the Corporations Act 2001. Matters arising subsequent to the end of the financial year On 9 August 2023, Beach appointed Mr Brett Woods as Managing Director and Chief Executive Officer (MD & CEO) to commence 21 February 2024 or such other date as mutually agreed. Mr Woods has over 25 years of experience in upstream oil and gas including most recently 10 years at Santos where he undertook a number of executive roles including Chief Operating Officer, Vice President Developments and Vice President Eastern Australia business unit. In the intervening period current non-executive director Mr Bruce Clement has been appointed interim Chief Executive Officer and continues as an executive director with Mr Morné Engelbrecht ending his tenure as Chief Executive Officer. Other than the matters described above, there has not arisen in the interval between 30 June 2023 and up to the date of this report, any item, transaction or event of a material and unusual nature likely, in the opinion of the directors, to affect substantially the operations of the Group, the results of those operations or the state of affairs of the Group in subsequent financial years, unless otherwise noted in the financial report. Audit independence declaration Section 307C of the Corporations Act 2001 requires our auditors, Ernst & Young, to provide the directors of Beach with an Independence Declaration in relation to the audit of the full year financial statements. This Independence Declaration is made on the following page and forms part of this Directors’ Report. This Directors' Report is signed in accordance with a resolution of directors made pursuant to section 298 (2) of the Corporations Act 2001. On behalf of the directors G S Davis Chairman Adelaide, 14 August 2023 52 Beach Energy Limited Annual Report 2023 Auditor's Independence Declaration 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 Beach Energy Limited As lead auditor for the audit of the financial report of Beach 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 Beach Energy Limited and the entities it controlled during the financial year. Ernst & Young L A Carr Partner 14 August 2023 A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation 53 2023 Remuneration in Brief (Unaudited) Remuneration to executive key management personnel in FY23 Consistent with FY23 outcomes, the Board and management have sought to ensure FY23 remuneration considers broader economic conditions, key project outcomes which have impacted Beach but also acknowledging key outcomes achieved throughout the year. A summary of the audited cost to the Company of executive key management personnel (KMP) remuneration is provided in Table 8. FY23 remuneration outcomes at a glance Fixed Remuneration 3% INCREASE Short Term Incentive (STI) STI AWARDED Long Term Incentive (LTI) LTI VESTED 2022 AGM Remuneration Report 97.36% ‘YES VOTE’ At the start of FY23, the board increased NED fees (excluding Chairman fees) by 3%, inclusive of the statutory 0.5% superannuation increase. This increase was the first since 2019, following a 10% reduction for 6 months to director and KMP fees during 2021. KMP’s Mr. Algar and Mr. Grant received a 3% increase to their TFR. No other KMP received an increase. The Board awarded an STI to senior executives. The 2020 STI performance rights converted automatically to shares on the retention condition being met on 1 July 2022. The 2019 LTI performance rights lapsed as the performance conditions were not met on 30 November 2022. Beach received more than 97% of ‘yes’ votes to adopt its Remuneration Report for the 2022 financial year. No specific feedback on Beach’s remuneration practices was received at the 2022 Annual General Meeting. Disclosures required in the remuneration report by the Corporations Act, particularly the inclusion of accounting values for LTI performance rights awarded but not vested, can vary significantly from the remuneration actually paid to Key Management Personnel. This is because the Accounting Standards require a value to be placed on a right at the time it is granted to a senior executive and then reported as remuneration even if ultimately the senior executive does not receive any actual value, for example because performance conditions are not met and the rights do not vest. The following table is a summary of remuneration actually paid or payable to executive KMP for FY23. It is not audited. Table 1: Remuneration to executive key management personnel (non-IFRS and unaudited) Name M Engelbrecht (3) Chief Executive Officer I Grant Chief Operating Officer AM Barbaro Chief Financial Officer S Algar Group Executive Exploration & Subsurface P Hogarth Acting Group Executive Corporate Strategy & Commercial Former KMP T Nador (4) Group Executive Development Total Total Fixed Remuneration Salary $ Super $ STI cash bonus (1) $ 1,238,500 27,500 67,821 649,210 27,500 26,778 472,500 27,500 25,879 649,210 27,500 37,775 436,654 27,500 24,024 Other (2) $ – – – – – Total Cash $ 1,333,821 703,488 525,879 714,485 488,178 76,712 8,055 – 10,390 95,157 3,522,786 145,555 182,277 10,390 3,861,008 (1) This amount represents the cash portion of the STI for FY23, which is expected to be paid in September 2023. (2) Other remuneration includes the payment of accrued employee entitlements and allowances paid under the terms and conditions of employment such as relocation and retention allowances. (3) Mr Engelbrecht’s tenure as CEO and a KMP ceased on 9 August 2023. (4) T Nador ceased employment with Beach on 30 August 2022. 54 Beach Energy Limited Annual Report 2023 2023 Remuneration Report (Audited) This report has been prepared in accordance with section 300A of the Corporations Act 2001 (Cth) (Corporations Act) for the consolidated entity for the financial year ended 30 June 2023. It has been audited as required by section 308(3C) of the Corporations Act and forms part of the Directors’ Report. Key management personnel The Company’s KMP are listed in Table 2. They are the Company’s non-executive directors (NED) and executive KMP who have authority and responsibility for planning, directing and controlling the activities of the Company, directly or indirectly. Table 2: Key management personnel during FY23 Name Executive KMP M Engelbrecht (1) I Grant AM Barbaro S Algar P Hogarth Non-executive Directors G S Davis B F W Clement (2) M H Hall S G Layman P S Moore R J Richards R K Stokes Former KMP P J Bainbridge R Jager C D Beckett T Nador Position Period as KMP during the year Chief Executive Officer Chief Operating Officer Chief Financial Officer Group Executive Exploration and Subsurface Acting Group Executive Corporate Strategy and Commercial All of FY23 All of FY23 All of FY23 All of FY23 All of FY23 Independent Chairman Non-executive Director Non-executive Director Non-executive Director Non-executive Director Non-executive Director Alternate Director All of FY23 8 May 2023 – 30 June 2023 All of FY23 All of FY23 All of FY23 All of FY23 All of FY23 Non-executive Director Non-executive Director Non-executive Director Group Executive Development 1 July 2022 – 31 March 2023 1 July 2022 – 16 November 2022 1 July 2022 – 16 November 2022 1 July 2022 – 30 August 2022 (1) Mr Engelbrecht’s tenure as CEO and a KMP ceased on 9 August 2023. (2) Mr Clement was appointed interim CEO on 9 August 2023 and continues as an executive director. Beach’s remuneration policy framework Beach’s vision is to be Australia’s premier multi-basin upstream oil and gas company. Beach’s remuneration framework seeks to focus executives on delivering this vision: – Fixed remuneration aligns to market practice and prevailing economic conditions. It seeks to attract, motivate, and retain executives focused on delivering Beach’s purpose. – ‘At risk’ performance-based incentives link to shorter- and longer-term Company goals. The goals contribute to the achievement of Beach’s purpose. – Longer term ‘at risk’ incentives align with shareholder objectives and interests. Beach benchmarks shareholder returns against peers considered to be alternative investments to Beach. Beach offers share based rather than all cash rewards to executives. – Beach may recover remuneration benefits paid if there has been fraud or dishonesty. – The Corporations Act and Beach’s Share Trading Policy prohibit hedging. Hedging is where a person enters a transaction to reduce the risk of an ‘at risk’ incentive. Beach’s Share Trading Policy is available at Beach’s website: www.beachenergy.com.au. How Beach makes decisions about remuneration The Board decides Beach’s KMP remuneration. It decides that remuneration based on recommendations by its Remuneration and Nomination Committee. The Committee’s members are all non-executive directors. Its charter is available at Beach’s website: www.beachenergy.com.au. Beach’s CEO may attend Committee meetings by invitation in an advisory capacity. Other executives may also attend by invitation. The Committee excludes executives from any discussion about their own remuneration. 55 2023 Remuneration Report (Audited) External advisers and remuneration advice Beach follows a protocol to engage an adviser to make a remuneration recommendation. The protocol ensures the recommendation is free from undue influence by management. The Board or Committee chair engages the adviser. The Board or Committee chair deals with the adviser on all material matters. Management involvement is only to the extent necessary to coordinate the work. The Board and Committee seek recommendations from the CEO about executive remuneration. The CEO does not make any recommendation about his own remuneration. The Board and Committee have regard to industry benchmarking information. How Beach links performance to incentives Beach’s remuneration policy includes short term and long-term incentive plans. The plans seek to align management performance with shareholder interests. The LTI links to an increase in total shareholder return over an extended period. The STI has equal proportions of cash and performance rights. Performance rights may convert to Beach shares. The following table shows some key shareholder wealth indicators. KPI and STI awards for FY22 and FY23 are detailed in Table 8. Table 3: Shareholder wealth indicators FY19 – FY23 Total revenue Net profit after tax Underlying net profit after tax Share price at year-end Dividends declared Reserves Production FY19 FY20 FY21 FY22 FY23 $2,077.7m $577.3m $560.2m 198.5 cents 2.00 cents 326 MMboe 29.4 MMboe $1,728.2m $499.1m $459.3m 152.0 cents 2.00 cents 352 MMboe 26.7 MMboe $1,562.0m $316.5m $363.0m 124.0 cents 2.00 cents 339 MMboe 25.6 MMboe $1,771.4m $500.8m $504.3m 172.5 cents 2.00 cents 283 MMboe 21.8 MMboe $1,646.4m $400.8m $384.8m 135.0 cents 4.00 cents 254.7 MMboe 19.5 MMboe Senior executive remuneration structure This section details the remuneration structure for senior executives. Remuneration mix Remuneration for senior executives is a mix of a fixed cash salary component and an ‘at risk’ component. The ‘at risk’ component means that specific targets or conditions must be met before a senior executive becomes entitled to it. 56 Beach Energy Limited Annual Report 2023 What is the balance between fixed and ‘at risk’ remuneration? The remuneration structure and packages offered to senior executives for the period were: – Fixed remuneration. – ‘At risk’ remuneration comprising: i. Short term incentive (STI) – an annual cash and equity-based incentive, which may be offered at the discretion of the Board, linked to Company and individual performance over a year. ii. Long term incentive (LTI) – equity grants, which may be granted annually at the discretion of the Board, linked to performance conditions measured over three years. The balance between fixed and ‘at risk’ remuneration depends on the senior executive’s role. The CEO has the highest level of ‘at risk’ remuneration reflecting the greater level of responsibility of this role. Table 4 sets out the relative proportions of the three elements of the executives KMP’s total remuneration packages for FY22 and FY23. Table 4: Remuneration mix (1) Position CEO (2) 2023 2022 Other Executive KMP 2023 2022 Fixed Remuneration Performance based remuneration Total ‘at risk’ % 34 34 47 47 STI % LTI % 33 33 30 30 33 33 23 23 % 66 66 53 53 (1) The remuneration mix assumes maximum ‘at risk’ awards. Percentages shown later in this report reflect the actual incentives paid as a percentage of total fixed remuneration, movements in leave balances and other benefits and share based payments calculated using the relevant accounting standards. (2) A reference to the CEO also includes a CEO who was also a Managing Director. Fixed remuneration What is fixed remuneration? How is fixed remuneration reviewed? Senior executives are entitled to a fixed cash remuneration amount inclusive of the guaranteed superannuation contribution. The amount is not based upon performance. Senior executives may decide to salary sacrifice part of their fixed remuneration for additional superannuation contributions and other benefits. Fixed remuneration is determined by the Board based on independent external review or advice that takes account of the role and responsibility of each senior executive. It is reviewed annually against industry benchmarking information including the National Rewards Group Incorporated remuneration survey. Fixed remuneration for the year Total fixed remuneration (TFR) of KMP are provided in Table 1 and Table 8. Table 1 shows the actual realised cash remuneration that KMP received. Table 8 reports on the remuneration for KMP as required under the Corporations Act. 57 2023 Remuneration Report (Audited) Short Term Incentive (STI) What is the STI? The STI is part of ‘at risk’ remuneration offered to senior executives. It measures individual and Company performance over a 12-month period. The period coincides with Beach’s financial year. It provides equal parts of cash and equity that may vest subject to extra retention conditions. It is offered to senior executives at the discretion of the Board. How does the STI link to Beach’s objectives? The STI is an at-risk opportunity for senior executives. It rewards senior executives for meeting or exceeding key performance indicators. The key performance indicators link to Beach’s key purpose. The STI aims to motivate senior executives to meet Company expectations for success. Beach can only achieve its purpose if it attracts and retains high performing senior executives. An award made under the STI has a retention component. Half is paid in cash and half is issued as performance rights with service conditions attached. What are the performance conditions or KPIs? Beach's key performance indicators (KPIs) are set by the Board for each 12-month period beginning at the start of a financial year. They reflect Beach's financial and operational goals that are essential to it achieving its purpose. Senior executives also have individual KPIs to reflect their particular responsibilities. For the reporting period, the performance measures comprised: STI Measures Company KPIs Production Statutory NPAT Project Delivery Operating Expenditure (Opex) Personal safety Process safety Environment Individual KPIs Refer to Table 6 for more information. Weighting 75% 15% 15% 15% 15% 5% 5% 5% 25% Individual KPIs link to Beach’s strategy and strategic plan. Individual KPIs relate to areas where senior executives are able to influence or control outcomes. KPIs may include delivery of cost savings; development of project specific plans to align with Beach’s strategic pillars; specific initiatives for developing employee capability; funding capacity; improvements in systems to achieve efficiencies; specific commercial or corporate milestones; or specific safety and environmental and sustainability targets. Are there different performance levels? The Board sets KPI measures at threshold, target and stretch levels. A participant must achieve the threshold level to entitle them to any payment for an individual KPI. The stretch level is the greatest performance outcome for an individual KPI. What is the value of the STI award that can be earned? How are the performance conditions assessed? Is there a threshold level of performance or hurdle before an STI is paid? Incentive payments are based on a percentage of a senior executive’s fixed remuneration. The CEO can earn up to a maximum of 100% of his fixed remuneration. The value of the award that can be earned by other senior executives is up to a maximum of 65% of their fixed remuneration. The KPIs are reviewed against an agreed target. The Board assesses the extent to which KPIs were met for the period after the close of the relevant financial year and once results are finalised. The Board assesses senior executive performance on the CEO’s recommendation. The Board assesses the achievement of the KPIs for the CEO. Yes. At the end of Beach's financial year there is a calculation of return on capital. There is also a calculation of a one year relative total shareholder return against the ASX 200 Energy Index. Refer to Table 5 below. Table 5: Two-tiered test Measures Green Red One year Relative Total Shareholder Return against the ASX 200 Energy Index (Index Return) for the Performance Period Return on capital Employed (1) > = Index return > = 10% < Index return < 10% (1) Return on capital Employed (ROCE) is based on statutory NPAT/average total equity (being the average total equity at the beginning and end of the financial year). The following determines the impact of the hurdle measures on the STI calculation: – If both hurdle measures are met, then up to 100% of the STI award calculation is available; – If one hurdle measure is met, then up to 50% of STI award calculation is available; – If both hurdle measures are not met, then no STI award will be calculated 58 Beach Energy Limited Annual Report 2023 What happens if an STI is awarded? On achievement of the relevant KPIs, Beach pays half of the STI award in cash. Beach includes cash awards in its financial statements for the relevant financial year. Beach pays cash awards after the end of its financial year, usually in September. Beach issues the remaining half of the STI award value in performance rights. Performance rights vest over one and two years if the senior executive remains employed by Beach at each vesting date. If a senior executive leaves Beach before the vesting date the performance rights lapse. The Board may exercise its discretion for early vesting if the senior executive leaves Beach due to death or disability. The Board may exercise its discretion for early vesting in the event of a change of control of Beach. The Board also has a general discretion to allow early vesting of performance rights. The Board needs exceptional circumstances to consider exercising that general discretion. STI Performance for the year At the completion of the financial year the Board tested each senior executive’s performance against the STI performance conditions set for the year. The results of the two hurdle measures were: FY23 measures Outcome Hurdle One year Relative Total Shareholder Return against ASX 200 Energy Total Return Index at the end of the Performance Period Return on capital at the end of the Performance Period -19.4% 11% > or = 13.5% > or = 10% The percentage of the maximum STI that will be paid or forfeited for the period for each executive KMP was as follows (paid/forfeited): Mr Engelbrecht 11%/89%, Ms Barbaro 16%/84%, Mr Grant 12%/88%, Mr Hogarth 16%/84%, Mr Algar 17%/83%. The STI awards made reflect Beach’s performance for FY23, with outcomes of the Company related performance conditions that make up a fixed percentage of the STI KPIs provided in Table 6. The Company KPIs outlined in Table 6 are aligned to Beach strategic priorities. To deliver against the Beach strategy and annual business plan, Beach cascades performance goals from the CEO through to the Executive and management down to every employee in the organisation. It is intended that all employees can demonstrate a link between their individual goals, Divisional goals and Beach strategy. While most KPIs focus on financial outcomes and growth, at Beach, nothing is more crucial than the safety of our people and the preservation of the environment in which we operate. At Beach, safety takes precedence, and it starts with our leadership. Our CEO empowers every staff member with the authority to halt any job immediately if they perceive that it’s being conducted unsafely. By fostering a culture that values safety above all else, we strive to create a workplace where everyone can thrive without compromising their welfare or that of the environment. Safety is at the heart of everything we do at Beach. It is not merely a box to check off; it is a fundamental value that guides all of our actions and decisions. Table 6: Outcome of FY23 STI Company KPIs Measure and link to strategy Weight Targets & FY23 Outcome Production (Mmboe) Production is at the core of our operating philosophy, underpinned by the Integrated Production Management process. Achieving our production target delivers value to our shareholders and provides earnings, supporting our purpose to ‘sustainably deliver energy for our communities’. The production KPI is an all-inclusive operated and non-operated basis. Statutory NPAT ($m) Statutory NPAT reflects the financial performance of Beach’s underlying operating business. Stretch performance is achieved through meeting production targets, strength in commodity markets, sales revenue and cost reduction. Threshold Target Stretch 15% Outcome Outcome Due to various factors including delays in Cooper Basin operated and non-operated well connections and the fact that only 2 out 4 drilled wells were brought online in Otway Phase 5, Beach’s final FY23 production was 19.5Mmboe. The lower production resulted in a 0% outcome on this metric reflecting the importance of production in delivering shareholder value. Threshold Target Stretch 15% Outcome Outcome FY23 Statutory NPAT of $401 million was impacted by softer production as outlined above, coupled with increased non-operated Cooper Basin JV field operating costs as a result of unplanned events and maintenance. The lower Statutory NPAT outcome resulted in a 0% outcome on this metric. Result 0% 0% 59 2023 Remuneration Report (Audited) Measure and link to strategy Weight Targets & FY23 Outcome Project Delivery (milestones achieved) A key strategic pillar for Beach is Delivering Growth. This growth is delivered through on time and on budget project delivery and measured by achievement of milestones. 15% Threshold Target Stretch Outcome Outcome Operating Cost (net Beach) Maintaining financial strength will be achieved through management of our operating costs. Operating costs includes both operated and non-operated operating costs. Two of four Otway Phase 5 wells were brought online after dealing with a flowline issue during May 2023 and were commissioned without issue and are performing as expected. Enterprise pipeline construction was also completed in June. There was also delay caused to the non-operated Waitsia Stage 2 project, due to the voluntary administration of Clough which was outside of control of Beach, with a new contractor being appointed. Outcomes on this KPI were impacted by factors outside of Beach direct control resulting in an outcome below target. Threshold Target Stretch 15% Outcome Outcome Field operating costs of $282 million were higher than threshold due to unplanned non-operated Cooper Basin JV maintenance costs following a number of unplanned events. This was partly offset by the outperformance of Operated asset field operating costs. Below threshold performance resulted in 0% outcome for this metric. Personal safety (TRIFR) At Beach, safety takes precedence in everything we do. Beach is committed to providing a safe and healthy working environment for all employees. Beach has included other safety and reliability measures in the annual Sustainability Report available on Beach’s website. Process safety Beach is focused on ensuring all assets are operated in a safe, reliable and responsible manner through the application of sound design principles, engineering, and operating and maintenance practices. This enables Beach to prevent and control hazardous events. 5% 5% Threshold Target Stretch Outcome Outcome Beach recorded its second-best safety performance achieving a TRIFR of 2.4. This represents a 45% improvement compared to FY22. Threshold Target Stretch Outcome Outcome Performance was on target with zero Tier 1 loss of primary containment process safety events and one low risk Tier 2 event. Environment (events) Threshold Target Stretch Beach strives to reduce the environmental impact of its activities. 5% Total Company KPI 75% Outcome Outcome Beach recorded two hydrocarbon spills, which were immediately remediated to prevent any harm to the environment. Result 5.0% 0% 4.3% 3.3% 1.7% 14.3% 60 Beach Energy Limited Annual Report 2023 FY23 Role Specific individual STI Outcomes For CEO and other Executive, 25% of the total STI payable is based on individual performance, with 75% payable from Company performance against KPIs. Table 7 below outlines role specific KPI’s for CEO and other KMP and key achievements against each of these. Note, some KPI’s contain commercially sensitive information that cannot be detailed here. KMP Role Specific KPI’s M Engelbrecht (1) – Delivery of gas to plant from newly developed opportunities – Establishment of infrastructure ahead of new opportunities coming on board – Delivery against overarching company KPIs I Grant S Algar AM Barbaro P Hogarth – Optimise core producing assets through efficient operations and maintenance delivery – Alignment of growth opportunities for shareholder return – Project delivery on time and within budget – Execution of existing asset performance including new wells in line with oil production plan – Delivery against capital management framework – Drilling of new wells and approval for future development opportunities – Corporate and operational cost management – Balance sheet improvement – Investor relations outcomes – Capital management framework – Commercial management – Marketing and trading leadership – All necessary sales, transport and processing agreements in place – New Energy partnership portfolio development Role Specific KPI Outcome (max 25%) 10.0% 10.0% 20.0% 17.5% 17.5% (1) Mr Engelbrecht’s tenure as CEO and a KMP ceased on 9 August 2023. All Executives have included in their role specific KPI’s improvement to employee engagement, development of employees, sustainability activities toward achieving net equity emissions intensity reduction by 2030 and assessing future energy opportunities against overarching strategic objectives. Table 8 provides a summary of total STI paid to each Executive for FY23 giving consideration to Company and Individual performance as outlined. STI performance rights relating to the 2020 performance period converted automatically to shares because the relevant senior executives remained employed by the Company on 1 July 2022. A total of 73,164 shares were transferred. No STI performance rights relating to the 2021 performance period were issued. 61 2023 Remuneration Report (Audited) STI performance rights issued or in operation in FY23 The fair value of services received in return for STI rights (see Table 13) granted is measured by reference to the fair value of STI rights granted calculated using the Binomial or Black-Scholes Option Pricing Models. The contractual life of the STI rights is used as an input into the valuation model. The expected volatility is based on the historic volatility (calculated based on the weighted average remaining life of the rights), adjusted for any expected changes to future volatility due to publicly available information. The risk free rate is based on Commonwealth Government bond yields relevant to the term of the performance rights. Long Term Incentive (LTI) What is the LTI? The LTI is an equity based ‘at risk’ incentive plan. The LTI aims to reward results that promote long term growth in shareholder value or total shareholder return (TSR). Beach offers LTIs to senior executives at the discretion of the Board. How does the LTI link to Beach’s key purpose? The LTI links to Beach’s key purpose by aligning the longer term ‘at risk’ incentive rewards with outcomes that match shareholder objectives and interests by: How are the number of rights issued to senior executives calculated – benchmarking shareholder returns against a group of companies considered alternative investments to Beach; – giving share based rather than cash-based rewards to executives. This links their own rewards to shareholder expectations of dividends and share price growth. The number of performance rights granted to the executives under the LTI is calculated as fixed remuneration at 1 November of the Financial year times the relevant percentage divided by the market value. The Market Value is the market value of a fully paid ordinary share in the Company, calculated using a five day VWAP, up to and including the date the performance rights are granted. This method of calculating the number of performance rights does not discount for the value of anticipated dividends during the performance period. What equity based grants are given and are there plan limits? What is the performance condition? Beach grants performance rights using the formula set out above. If the performance conditions are met, senior executives have the opportunity to acquire one Beach share for every vested performance right. There are no plan limits as a whole for the LTI. This is due to the style of the plan and advice by external remuneration consultants about individual plan limits. Individual limits for the plans that are currently operational are set out in Table 8. The performance condition is based on Beach’s Total Shareholder Return (TSR) relative to the ASX 200 Energy Total Return Index. The initial out-performance level is set at the Index return plus 5.5% compound annual growth rate (CAGR) over the three year performance period, such that: – < the Index return – 0% vesting; – = the Index return – 50% vesting; – between the Index return and Index + 5.5% – a prorated number will vest; – = or > Index return + 5.5% – 100% vesting. TSR is a measure of the return to shareholders over a period of time through the change in share price and any dividends paid over that time. The dividends are notionally reinvested to perform the calculation. Beach chose this performance condition to align senior executive remuneration with increased shareholder value. The Board has reinforced that alignment by imposing two more conditions. First, the Board sets a threshold level for the executive to meet before making an award. Secondly, the Board will not make an award if Beach’s TSR is negative. All entitlements to shares on the vesting of LTI performance rights are currently satisfied by the purchasing of shares on market which does not result in any dilution to shareholders equity. The Board reserves the discretion for early vesting in the event of a change of control of the Company. Adjustments to a participant’s entitlements may also occur in the event of a company reconstruction and certain share issues. Following a period of significant change in FY22 with the loss of several key executives, the Board granted retention rights in FY23 to a number of the company’s KMP. These rights were granted as of 1 July 2022 and in order to vest, the relevant individuals must remain employed with Beach and continue to satisfactorily perform until at least 30 June 2025. On vesting, each right entitles the executive to one ordinary share in Beach. The Board considers that the grants of retention rights will ensure that Beach has the necessary strategic and operational leadership in place to enhance long-term shareholder value. Why choose this performance condition? Is shareholders equity diluted when shares are issued on vesting of performance rights or exercise of options? What happens to LTI performance rights on a change of control? Special Retention Rights Offer 62 Beach Energy Limited Annual Report 2023 Table 7: Details of LTI equity awards issued, in operation or tested during the year Details Type of grant 2019, 2020, 2021 and 2022 Performance Rights Performance & Retention rights Calculation of grant limits for senior executives Max LTI is 100% of Total Fixed Remuneration (TFR) for CEO Max LTI is 50% of TFR for other senior executives Grant date 2022 Performance Rights 1 Dec 2022 2022 Retention Rights 1 Jul 2022 2021 Performance Rights 31 Dec 2021/31 Mar 2022/30 Jun 2022 2020 Performance Rights 14 Dec 2020/31 May 2021/30 Sep 2021 2019 Performance Rights 19 Dec 2019/14 Dec 2020 Issue price of performance rights Granted at no cost to the participant Performance period Note: the date immediately after the end of the performance period is the first date that the performance rights vest and become exercisable Expiry/lapse Expiry date Note: upon vesting of performance rights, there is a two-year period over which they may be exercised and converted into full paid ordinary shares in Beach. 2022 Performance Rights 1 Dec 2022 – 30 Nov 2025 2022 Retention Rights 1 Jul 2022 – 30 Jun 2025 2021 Performance Rights 1 Dec 2021 – 30 Nov 2024 2020 Performance Rights 1 Dec 2020 – 30 Nov 2023 2019 Performance Rights 1 Dec 2019 – 30 Nov 2022 Performance rights lapse if vesting does not occur on testing of performance condition 2022 Performance Rights 30 Nov 2027 2022 Retention Rights 30 June 2027 2021 Performance Rights 30 Nov 2026 2020 Performance Rights 30 Nov 2025 2019 Performance Rights 30 Nov 2024 Exercise price on vesting Not applicable – provided at no cost What is received upon vesting and exercise? One ordinary share in Beach for every performance right Status 2022 Performance Rights In progress 2022 Retention Rights In progress 2021 Performance Rights In progress 2020 Performance Rights In progress 2019 Performance Rights Testing complete. Resulted in lapsing of performance rights 63 2023 Remuneration Report (Audited) Details of LTI performance rights issued or in operation in FY23 The fair value of services received in return for LTI performance rights (see Table 13) granted is measured by reference to the fair value of LTI performance rights granted calculated using the Binomial or Black-Scholes Option Pricing Models. The estimate of the fair value of the services received for the LTI performance rights and options issued are measured with reference to the expected outcome, which may include the use of a Monte Carlo simulation. The contractual life of the LTI performance rights is used as an input into this model. Expectations of early exercise are incorporated into a Monte Carlo simulation method where applicable. The expected volatility is based on the historic volatility (calculated based on the weighted average remaining life of the rights or options), adjusted for any expected changes to future volatility due to publicly available information. The risk free rate is based on Commonwealth Government bond yields relevant to the term of the performance rights. Employment agreements – senior executives The senior executives have employment agreements with Beach. The provisions relating to duration of employment, notice periods and termination entitlements of the senior executives are as follows: Chief Executive Officer The CEO’s employment agreement commenced on 19 May 2022 and is ongoing until terminated by either Beach or Mr Engelbrecht on six months’ notice. Beach may discharge such notice obligation by payment in lieu. Beach must pay any amount owing but unpaid to the employee whose services have been terminated at the date of termination. Beach may terminate the CEO’s employment at any time for serious misconduct or breach without notice. In certain circumstances Beach may terminate the employment on notice of not less than three months for issues concerning the CEO’s performance that have not been satisfactorily addressed. Mr Engelbrecht’s tenure as CEO ended on 9 August 2023. He will remain an employee and continue to receive his salary entitlements for the duration of his 6 month notice period until 9 February 2024. Mr Engebrecht’s rights under the executive incentive plans will either lapse or stay on foot in accordance with the board’s discretion. These determinations will be made in due course and reported in next year’s remuneration report. Other senior executives Other senior executives have employment agreements that are ongoing until terminated by either Beach upon six months’ notice or the senior executive upon giving six-months’ notice. Beach may terminate a senior executive’s appointment for cause (for example, for serious breach) without notice. Beach must pay any amount owing but unpaid to the employee whose services have been terminated at the date of termination. Details of total remuneration for KMP calculated as required under the Corporations Act for FY22 and FY23 Legislative and Australian Accounting Standards reported remuneration for KMP Details of the remuneration package by value and by component for senior executives in the reporting period and the previous period are set out in Table 8. These details differ from the actual payments made to senior executives for the reporting period that are set out in Table 1. 64 Beach Energy Limited Annual Report 2023 Other Termi- nation Pay- ments $ Total at risk % Total $ Total issued in equity % – 2,255,636 – 2,033,439 1,215,440 – 968,836 – 712,377 – 296,333 – 1,205,233 – 1,066,841 – 624,014 – 129,529 – 39 40 40 27 18 14 40 29 14 19 – 9 – 36 – – 33 28 32 22 38 18 13 4 37 20 9 9 – 9 – 31 – – 28 19 Table 8: Senior executives’ remuneration for FY22 and FY23 required under the Corporations Act Short Term Employee Benefits Share based payments (1) Other long term benefits Fixed Remun- eration (2) Name Year $ A Barbaro I Grant (5) (6) M Engelbrecht(6) (7) 2023 1,266,000 2022 1,041,757 676,710 2023 2022 657,000 2023 500,000 236,710 2022 676,710 2023 711,750 2022 464,154 2023 97,274 2022 S Algar (5) (6) P Hogarth Annual Leave (3) $ STI Cash (4) $ 67,821 99,258 187,666 276,937 26,778 48,818 88,079 49,184 25,879 85,059 29,893 16,665 37,775 47,333 90,748 49,820 24,024 69,437 12,972 7,696 LTI/ Retention Rights $ 479,037 329,930 347,040 99,163 55,034 – 312,237 64,360 36,748 5,913 STI Rights (4) $ Long Service Leave (3) $ 253,386 124,149 116,094 75,410 35,085 12,456 131,178 150,163 20,557 5,406 90,134 73,000 – – 11,320 609 – – 9,094 268 Former Senior Executives T Nador (8) M Kay L Marshall TOTAL 2023 84,767 2022 498,000 – 2023 440,333 2022 – 2023 384,604 2022 (44) 63,541 – – – – 69,023 132,236 – – – 29,575 (64,815) 54,579 – 525,964 – (83,965) – – – 28,374 – (13,216) – – – (52,729) – (4,834) – – – 619,250 – 34,462 19,908 616,120 – 1,762,451 – 346,626 2023 3,668,341 2022 4,067,428 182,277 349,861 473,170 630,865 1,165,281 995,944 556,300 382,742 110,548 16,314 – 6,032,608 7,220,175 653,712 (1) In accordance with the requirements of the Australian Accounting Standards, remuneration includes a proportion of the notional value of equity compensation granted or outstanding during the year. The fair value of equity instruments are determined as at the grant date and then progressively expensed over the vesting period. The amount included as remuneration is not related to or indicative of the benefit (if any) that individuals may ultimately realise should the rights vest. The fair value of the rights as at the date of their grant has been determined in accordance with principles set out in Note 4 to the Financial Statements. (2) Fixed remuneration comprises base salary and superannuation and other contractual payments treated as remuneration including retention and relocation payments where applicable. (3) This amount represents the movement in the relevant leave entitlement provision during the year. (4) Only up to 50% of the STI award calculation is available for FY23 with only one of the two hurdle measures being met during the year. STI awards are then calculated based on a weighting of 75% on Company KPIs and 25% on Individual KPIs. STI awards are paid 50% in cash which is expected to be paid in September 2023 and 50% in performance rights which vest equally over a further service period of one and two years respectively, the valuations of which are expensed over the relevant performance and vesting period. (5) Mr Grant and Mr Algar are entitled to retention payments on the first and third anniversary of their commencement dates. The retention payments are payable in shares, equal to $100,000 for Mr Grant and $125,000 for Mr Algar respectively, based on a 5 day VWAP as calculated when their contracted entitlements were created. (6) Mr Engelbrecht, Mr Grant and Mr Algar are entitled to retention performance rights on 30 June 2025 as part of a special retention offer in December 2022. See page 62 and Table 7. (7) Mr Engelbrecht’s tenure as CEO and a KMP ceased on 9 August 2023. (8) Mr Nador ceased to be a KMP on 30 August 2022. 65 2023 Remuneration Report (Audited) Remuneration policy for non-executive directors The fees paid to non-executive directors are determined using the following guidelines. Fees are: – not incentive or performance based but are fixed amounts; – determined by reference to the nature of the role, responsibility and time commitment required for the performance of the role including membership of board committees; – are based on independent advice and industry benchmarking data; and – driven by a need to attract a diverse and well-balanced group of individuals with relevant experience and knowledge. Following a benchmarking review by the Remuneration & Nomination Committee, the Board increased all non-executive director's fees (except Chairman fees, which was already at median) by 3% inclusive of the statutory 0.5% increase in superannuation from 1 July 2022. This increase was the first to NED fees since 2019 and followed a 10% reduction for 6 months in 2021. The remuneration of Beach non-executive directors remains within the aggregate annual limit of $1,500,000 approved by shareholders at the 2016 annual general meeting. The remuneration for non-executive directors comprises directors’ fees, board committee fees and superannuation contributions to meet Beach’s statutory superannuation obligations. Directors who perform extra services for Beach or make any special exertions on behalf of Beach may be remunerated for those services in addition to the usual directors’ fees. Non-executive directors are also entitled to be reimbursed for their reasonable expenses incurred in the performance of their directors’ duties. Alternate directors do not receive any remuneration for those services. However, Beach will reimburse any reasonable expense incurred in attending board meetings as an alternate. Details of the fees payable to non-executive directors for Board and committee membership for FY23 are set out in Table 9. Table 9: FY23 non-executive directors’ fees and board committee fees per annum Board (1) Board Committee Chairman/ Deputy Chairman $ 305,000/ 126,175 Member $ Chairman Audit $ Member Audit $ Chairman Remuneration and Nomination $ Member Remuneration and Nomination $ Chairman Risk, Corporate Governance and Sustainability $ Member Risk, Corporate Governance and Sustainability $ 126,175 25,750 15,450 25,750 15,450 25,750 15,450 (1) The Chairman does not receive additional fees for committee work. The fees shown are inclusive of the statutory superannuation contribution. Remuneration policy for executive directors Executive directors are remunerated on the basis of their executive role in accordance with the terms of their employment agreement. They do not receive any additional director fees. 66 Beach Energy Limited Annual Report 2023 Following a review of directors’ fees at the conclusion of FY23, directors’ fees will remain the same next year. See Remuneration Lookahead for FY24 below. Table 10: Non-executive directors’ remuneration for FY22 and FY23 Name G S Davis (1) B F W Clement (2) M H Hall (3) S G Layman (4) P S Moore (5) R J Richards (6) Former Directors P J Bainbridge (7) C D Beckett (8) R J Jager (9) J C Morton (10) R K Stokes (11) Total Directors Fees (including committee fees) $ Superannuation $ 305,000 305,000 16,962 – 128,167 74,995 159,535 147,500 161,096 147,727 142,149 138,636 110,343 134,145 52,079 144,022 48,548 65,036 – 50,000 – 50,000 1,123,879 1,257,061 – – 1,781 – 13,458 7,500 – – 16,915 14,773 14,926 13,864 7,463 13,414 5,468 14,402 5,098 6,504 – – – – 65,109 70,457 Year 2023 2022 2023 2022 2023 2022 2023 2022 2023 2022 2023 2022 2023 2022 2023 2022 2023 2022 2023 2022 2023 2022 2023 2022 Total $ 305,000 305,000 18,743 – 141,625 82,495 159,535 147,500 178,011 162,500 157,075 152,500 117,806 147,559 57,547 158,424 53,646 71,540 – 50,000 – 50,000 1,188,988 1,327,518 (1) No superannuation contributions were made on behalf of Mr Davis. Director’s fees for Mr Davis are paid to a related entity. Mr Davis does not receive additional fees for committee work. (2) Mr Clement was appointed as a director on 8 May 2023 and is chair of the Risk, Corporate Governance and Sustainability Committee (appointed 22 June 2023). Mr Clement was appointed interim CEO on 9 August 2023 and continues as an executive director. (3) Ms Hall is a member of the Risk, Corporate Governance and Sustainability Committee. (4) Ms Layman is chair of the Audit Committee and a member of the Risk, Corporate Governance and Sustainability Committee (appointed 12 April 2023) and the Remuneration and Nomination Committee (appointed 24 March 2023). (5) Dr Moore is the chair of the Remuneration and Nomination Committee and a member of the Risk, Corporate Governance and Sustainability Committee (he was chair until 22 June 2023) and the Audit Committee (appointed 24 March 2023). (6) Mr Richards is a member of both the Audit Committee and the Remuneration and Nomination Committee. (7) Mr Bainbridge was both a member of the Risk, Corporate Governance and Sustainability Committee and the Audit Committee until his retirement on 31 March 2023. (8) Mr Beckett was Deputy Chairman and chair of the Remuneration and Nomination Committee until his retirement on 16 November 2022. (9) Mr Jager was a member of the Risk, Corporate Governance and Sustainability Committee until his retirement on 16 November 2022. (10) Ms Morton retired as a director on 10 November 2021. (11) Mr Stokes was an alternate director for Ms Hall during FY23. He did not derive any separate remuneration for this role. Mr Stokes was re-appointed a non-executive director of Beach on 23 July 2023. 67 2023 Remuneration Report (Audited) Other KMP disclosures The following three tables show the movements during the reporting period in shares and performance rights over ordinary shares in the Company held directly, indirectly or beneficially by each KMP and their related entities. Performance rights held by KMP The following table details the movements during the reporting period in performance rights over ordinary shares in the Company held directly, indirectly or beneficially by each KMP and their related entities. Table 11: Movements in performance rights held by key management personnel Rights CEO M Engelbrecht (1) Senior executives I Grant A Barbaro S Algar P Hogarth Former senior executives T Nador(2) Total Opening balance Granted Vested/ exercised Lapsed Other Closing balance 1,365,145 1,303,669 (14,679) (125,961) 456,158 – 442,402 144,809 662,623 327,602 664,180 60,135 – – – – – – – (33,359) 319,614 2,728,128 – 3,018,209 – (14,679) (319,614) (478,934) – – – – – – – 2,528,174 1,118,781 327,602 1,106,582 171,585 – 5,252,724 (1) Mr Engelbrecht’s tenure as CEO and a KMP ceased on 9 August 2023. (2) Mr Nador ceased to be a KMP on 30 August 2022. The following table details the movements during the reporting period in ordinary shares in the Company held directly, indirectly or beneficially by each KMP and their related entities. Table 12: Shareholdings of key management personnel Ordinary Shares Directors G S Davis P J Bainbridge (2) C D Beckett (2) M H Hall S G Layman P S Moore R J Richards R K Stokes (3) R J Jager (2) B F W Clement(4) CEO M Engelbrecht (5) Senior executives I Grant A Barbaro S Algar P Hogarth Former senior executives T Nador(6) Total Opening balance Purchased Issued on exercise of perform- ance rights Sold Other (1) 320,101 137,320 91,678 17,068 45,000 44,200 488,053 150,000 – – 579,865 78,679 – 160,775 – – 2,112,739 – – – – – – – – – – – – – – – – – – – – – – – – – – – 14,679 – – – – – 14,679 – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – Closing balance 320,101 137,320 91,678 17,068 45,000 44,200 488,053 150,000 – – 594,544 78,679 – 160,775 – – 2,127,418 (1) Relates to changes resulting from individuals becoming or ceasing to be KMPs during the period. (2) The movements in this table relate to the period up to the dates of retirement of Mr Bainbridge (31 March 2023), Mr Beckett (16 November 2022) and Mr Jager (16 November 2022). (3) Mr Stokes was an alternate director for M Hall during FY23. He was re-appointed a non-executive director on 23 July 2023. (4) Mr Clement was appointed interim CEO on 9 August 2023 and continues as an executive director. (5) Mr Engelbrecht’s tenure as CEO and a KMP ceased on 9 August 2023. (6) Mr Nador ceased to be a KMP on 30 August 2022. Specific details of the number of LTI and STI performance rights granted, vested/exercised and lapsed in FY23 for KMP are set out in Table 13. 68 Beach Energy Limited Annual Report 2023 Table 13: Details of LTI and STI Performance Rights Perform- ance rights on issue at 30 June 2022 125,961 14,679 165,976 788,678 269,851 – – – – 1,365,145 181,492 274,666 – – – – 456,158 – – – – – 167,736 274,666 – – – – 442,402 33,359 43,956 67,494 – – – 144,809 46,691 64,729 208,194 319,614 Date of grant 19 Dec 2019 25 Nov 2020 14 Dec 2020 31 Mar 2022 30 Jun 2022 21 Nov 2022 21 Nov 2022 1 Jul 2022 1 Dec 2022 14 Dec 2020 31 Dec 2021 21 Nov 2022 21 Nov 2022 1 Jul 2022 1 Dec 2022 13 Oct 2021 21 Nov 2022 21 Nov 2022 1 Dec 2022 31 May 2021 31 Dec 2021 21 Nov 2022 21 Nov 2022 1 Jul 2022 1 Dec 2022 19 Dec 2019 14 Dec 2020 31 Dec 2021 21 Nov 2022 21 Nov 2022 1 Dec 2022 14 Dec 2020 31 May 2021 31 Dec 2021 Fair Value $ 1.4600 1.7900 1.0300 0.8600 1.0500 1.6800 1.6600 1.4100 0.6000 1.0300 0.6900 1.6800 1.6600 1.4100 0.6000 0.6600 1.6800 1.6600 0.6000 0.4100 0.6900 1.6800 1.6600 1.4100 0.6000 1.4600 1.0300 0.6900 1.6800 1.6600 0.6000 1.0300 0.4100 0.6900 Name M Engelbrecht (2) Total Total ($) I Grant Total Total ($) A Barbaro Total Total ($) S Algar Total Total ($) P Hogarth Total Total ($) T Nador(3) Total Total ($) Granted – – – – – 80,787 80,787 425,220 716,875 1,303,669 1,299,514 Vested/ Exercised – (14,679) – – – – – – – (14,679) (26,275) Lapsed (125,961) – – – – – – – – (125,961) – – 25,695 25,694 425,220 186,014 662,623 796,988 168,598 8,721 8,720 141,563 327,602 225,339 – – 26,473 26,473 425,220 186,014 664,180 989,108 – – – 3,785 3,784 52,566 60,135 44,180 – – – – – – – – – – – – – – – – – – – – – – – – (33,359) – – – – – (33,359) (46,691) (64,729) (208,194) (319,614) – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – Other (1) – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – (1) Relates to changes resulting from individuals becoming KMP during the period. (2) Mr Engelbrecht’s tenure as CEO and a KMP ceased on 9 August 2023. (3) Mr Nador ceased to be a KMP on 30 August 2022. Perform- ance rights on issue at 30 June 2023 Date perform- ance rights vest and become exercisable – – 1 Dec 2022 1 Jul 2022 165,976 1 Dec 2023 788,678 1 Dec 2024 1 Dec 2024 269,851 1 Jul 2023 80,787 1 Jul 2024 80,787 425,220 30 Jun 2025 716,875 1 Dec 2025 2,528,174 181,492 1 Dec 2023 274,666 1 Dec 2024 1 Jul 2023 1 Jul 2024 425,220 30 Jun 2025 186,014 1 Dec 2025 25,695 25,694 1,118,781 168,598 1 Dec 2024 1 Jul 2023 1 Jul 2024 141,563 1 Dec 2025 8,721 8,720 327,602 167,736 1 Dec 2023 274,666 1 Dec 2024 1 Jul 2023 1 Jul 2024 425,220 30 Jun 2025 186,014 1 Dec 2025 26,473 26,473 1,106,582 – 1 Dec 2022 43,956 1 Dec 2023 67,494 1 Dec 2024 1 Jul 2023 1 Jul 2024 52,566 1 Dec 2025 3,785 3,784 171,585 1 Dec 2023 1 Dec 2023 1 Dec 2024 – – – – 69 2023 Remuneration Report (Audited) Looking ahead – Remuneration and related issues for FY24 Non-executive directors’ fees Directors fees’ will not be increased for FY24, having regard to company performance and shareholder returns during FY23. Minimum shareholding policy Beach will implement a Directors and Executive minimum shareholding policy in FY24 which will require that non-executive directors, the CEO and senior executives reporting to the CEO each acquire within a 5-year period and maintain a minimum shareholding in Beach as set out in the below table. Table 14: Minimum shareholding requirement Relevant individual NED CEO Executives Minimum shareholding requirement 100% of annual base fees (excl. committee fees and superannuation) 150% of total fixed remuneration (TFR) 75% of TFR Senior Executive Remuneration Senior executives will receive an average increase of 1.07% for FY24. These increases give consideration to benchmarking against a defined peer group with consideration to organisation size and complexity, and the Executives role and responsibilities. Superannuation Guarantee Effective from 1 July 2023, the Superannuation Guarantee (SG) minimum compulsory rate for all Australian employees is legislated to increase from 10.5% to 11%. In respect of all Australian employees, Beach has increased total fixed remuneration so that no employee suffers any real remuneration decrease as a consequence of the legislative change. The total fixed remuneration of non-executive directors is set out above. Employee Retention The ability to attract and retain the workforce remains of critical importance as Beach seeks to ensure our planning and engagement practices are optimised to deliver operational and project priorities. Throughout FY24 we will continue to optimise improvement opportunities in the following key areas: – Employee engagement – continued implementation of initiatives identified through the 2022 staff engagement survey and addition of further actions to be identified through the 2023 Employee Engagement Survey. – Reward and recognition – ensuring that Beach maintains an offering which enhances our employee value proposition. – Wellbeing – focussing on support for employees physical and mental wellbeing. – Resourcing – continued focus on ensuring remuneration practices are appropriate and recruitment process are as efficient and effective as possible. Leadership Development and Culture Development – Delivery of our values-based development program for all employees. – Beach remains focused on building a diverse, flexible, and safe culture. During FY24 we will be implementing a new Diversity, Equity and Inclusion framework. – Continued focus on increased diversity of candidate pools for externally recruited positions. – Launch of our first Reconciliation Action Plan (RAP). This RAP will help us further understand issues, options and clarify our long term vision for progressing positive change within the communities in which we operate. 70 Beach Energy Limited Annual Report 2023 Directors’ Declaration 1. In the directors' opinion: (a) the financial statements and notes set out on pages 73–115 are in accordance with the Corporations Act 2001, including: (i) complying with accounting standards, the Corporations Regulations 2001 and other mandatory professional reporting requirements; and (ii) giving a true and fair view of the consolidated entity's financial position as at 30 June 2023 and of its performance for the financial year ended on that date; and (b) there are reasonable grounds to believe that Beach will be able to pay its debts as and when they become due and payable. 2. The attached financial statements are in compliance with International Financial Reporting Standards, as noted in the Basis of Preparation which forms part of the financial statements. 3. At the time of this declaration, there are reasonable grounds to believe that the members of the Extended Closed Group identified in note 23 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 described in note 23. 4. 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. Signed in accordance with a resolution of the directors made pursuant to section 295(5) of the Corporations Act 2001 on behalf of the directors. G S Davis Chairman Adelaide, 14 August 2023 71 Financial Report 72 Financial Report Consolidated Statement of Profit or Loss and Other Comprehensive Income Consolidated Statement of Financial Position Consolidated Statement of Changes in Equity Consolidated Statement of Cash Flows Notes to the Financial Statements Basis of preparation Results for the year 1. Operating segments 2. Revenue from contracts with customers and other income 3. Expenses 4. Employee benefits 5. Taxation 6. Earnings per share (EPS) Capital employed Inventories 7. 8. Property, plant and equipment (PPE) 9. Petroleum assets 10. Exploration and evaluation assets 11. Intangible assets 12. Interests in joint operations 13. Provisions 14. Leases 15. Commitments for expenditure Financial and risk management 16. Finances and borrowings 17. Cash flow reconciliation 18. Financial risk management Equity and group structure 19. Contributed equity 20. Reserves 21. Dividends 22. Subsidiaries 23. Deed of cross guarantee 24. Parent entity financial information 25. Related party disclosures Other information 26. Contingent liabilities 27. Remuneration of auditors 28. Subsequent events 72 73 74 75 76 77 77 80 80 81 82 83 85 88 89 89 89 90 94 95 96 97 99 101 102 102 103 104 107 107 108 108 109 110 112 113 113 113 115 115 Beach Energy Limited Annual Report 2023 Consolidated Statement of Profit or Loss and Other Comprehensive Income For the financial year ended 30 June 2023 Revenue Cost of sales Gross profit Other income Other expenses Operating profit before financing costs Interest income Finance expenses Profit before income tax expense Income tax expense Net profit after tax Other comprehensive income/(loss) Items that may be reclassified to profit or loss Net gain/(loss) on translation of foreign operations Other comprehensive income/(loss), net of tax Total comprehensive income after tax Basic earnings per share (cents per share) Diluted earnings per share (cents per share) The accompanying notes form part of these financial statements. Consolidated Note 2(a) 3(a) 2(b) 3(b) 16 16 5 6 6 2023 $million 1,646.4 (1,055.6) 590.8 10.3 (14.8) 586.3 4.4 (31.4) 559.3 (158.5) 400.8 3.0 3.0 403.8 17.58¢ 17.57¢ 2022 $million 1,771.4 (995.6) 775.8 12.0 (57.7) 730.1 0.2 (13.7) 716.6 (215.8) 500.8 (5.5) (5.5) 495.3 21.97¢ 21.94¢ 73 Consolidated Statement of Financial Position As at 30 June 2023 Current assets Cash and cash equivalents Receivables Inventories Current tax asset Contract assets Other Total current assets Non-current assets Property, plant and equipment Petroleum assets Exploration and evaluation assets Intangible assets Lease assets Contract assets Other Total non-current assets Total assets Current liabilities Payables Provisions Current tax liabilities Lease liabilities Contract liabilities Total current liabilities Non-current liabilities Payables Provisions Interest bearing liabilities Deferred tax liabilities Lease liabilities Total non-current liabilities Total liabilities Net assets Equity Contributed equity Reserves Retained earnings Total equity The accompanying notes form part of these financial statements. 74 Consolidated Note 2023 $million 2022 $million 17 18 7 8 9 10 11 14 18 13 14 18 13 16 5 14 19 20 218.9 238.1 161.2 24.2 14.2 13.5 670.1 4.0 4,482.1 562.2 77.6 23.6 16.8 58.5 5,224.8 5,894.9 329.9 91.2 12.1 11.0 – 444.2 2.7 971.6 383.3 201.0 14.2 1,572.8 2,017.0 3,877.9 1,863.3 751.8 1,262.8 3,877.9 254.5 222.5 101.4 – 15.6 101.8 695.8 6.2 3,759.5 444.7 77.1 31.7 26.8 60.3 4,406.3 5,102.1 334.9 89.4 48.3 14.7 4.3 491.6 3.4 855.2 87.3 106.4 18.3 1,070.6 1,562.2 3,539.9 1,862.3 815.6 862.0 3,539.9 Beach Energy Limited Annual Report 2023 Consolidated Statement of Changes in Equity For the financial year ended 30 June 2023 Balance as at 30 June 2021 Profit for the year Other comprehensive income/(loss) Total comprehensive income/(loss) for the year Transactions with owners in their capacity as owners: Shares issued during the year Shares purchased on market, net of tax (Treasury shares) Utilisation of Treasury shares on vesting of shares and rights under employee and executive incentive plans Final dividend paid Interim dividend paid Increase in share based payments reserve Transactions with owners Balance as at 30 June 2022 Profit for the year Other comprehensive income/(loss) Total comprehensive income/(loss) for the year Transactions with owners in their capacity as owners: Shares issued during the year Shares purchased on market, net of tax (Treasury shares) Utilisation of Treasury shares on vesting of shares and rights under employee and executive incentive plans Final dividend paid Interim dividend paid Increase in share based payments reserve Transactions with owners Contributed equity $million Retained earnings $million Note 1,859.5 – – – 361.2 500.8 – 500.8 19 19 19 21 21 19 19 19 21 21 1.0 (0.7) 2.5 – – – 2.8 – – – – – – – 1,862.3 – – – 862.0 400.8 – 400.8 0.8 (0.6) 0.8 – – – 1.0 – – – – – – – Balance as at 30 June 2023 1,863.3 1,262.8 The accompanying notes form part of these financial statements. Share based payment reserve $million 36.5 – – – – – (2.5) – – 2.1 (0.4) 36.1 – – – – – (0.8) – – 2.4 1.6 37.7 Foreign currency translation reserve $million (5.0) – (5.5) (5.5) – – – – – – – Profit distribution reserve $million 835.6 – – – – – – (22.8) (22.8) – (45.6) Total $million 3,087.8 500.8 (5.5) 495.3 1.0 (0.7) – (22.8) (22.8) 2.1 (43.2) (10.5) 790.0 3,539.9 – 3.0 3.0 – – – – – – – (7.5) – – – – – – (22.8) (45.6) – (68.4) 721.6 400.8 3.0 403.8 0.8 (0.6) – (22.8) (45.6) 2.4 (65.8) 3,877.9 75 Consolidated Statement of Cash Flows For the financial year ended 30 June 2023 Cash flows from operating activities Receipts from customers and other Payments to suppliers and employees Receipt on settlement of arbitration Payments for restoration Interest received Financing costs Income tax paid Net cash provided by operating activities Cash flows from investing activities Payments for property, plant and equipment Payments for petroleum assets Payments for exploration and evaluation assets Payments for intangible assets Proceeds on sale of joint operations interests Proceeds from sale of non-current assets Completion adjustment on acquisition of joint interest Net cash used in investing activities Cash flows from financing activities Proceeds from borrowings Repayment of borrowings Payment of the principal portion of lease liabilities Proceeds from employee incentive loans Payment for shares purchased on market (Treasury shares) Dividends paid Net cash provided by/(used in) financing activities Net increase/(decrease) in cash held Cash at beginning of financial year Effects of exchange rate changes on the balances of cash held in foreign currencies Cash at end of financial year The accompanying notes form part of these financial statements. Consolidated Note 2023 $million 2022 $million 1,802.2 (700.7) – (40.0) 4.2 (13.4) (123.7) 928.6 (0.2) (1,025.8) (138.2) (6.4) 0.7 0.2 – (1,169.7) 370.0 (75.0) (21.3) 0.8 (0.6) (68.4) 205.5 (35.6) 254.5 0.0 218.9 2,017.4 (701.5) 42.2 (15.9) 0.4 (9.5) (109.9) 1,223.2 – (796.2) (111.1) (5.5) 1.0 0.4 13.6 (897.8) 145.0 (230.0) (68.9) 1.0 (1.0) (45.6) (199.5) 125.9 126.7 1.9 254.5 17 17 17 17 21 76 Beach Energy Limited Annual Report 2023 Notes to the Financial Statements Notes to and forming part of the Financial Statements for the financial year ended 30 June 2023 BASIS OF PREPARATION Notes to the financial statements This section sets out the basis upon which the Group’s (comprising Beach Energy Limited and its subsidiaries) financial statements are prepared as a whole. Significant accounting policies and key judgements and estimates of the Group that summarise the measurement basis used and assist in understanding the financial statements are described in the relevant note to the financial statements or are otherwise provided in this section. The notes include information which is required to understand the financial statements that is material and relevant to the operations, financial position or performance of the Group. Information is considered material and relevant where the amount is significant in size or nature, it is important in understanding changes to the operations or results of the Group or it may significantly impact on future performance. Beach Energy Limited (Beach) is a for profit company limited by shares, incorporated in Australia and whose shares are publicly listed on the Australian Securities Exchange (ASX). The nature of the Group’s operations are described in the segment note. The consolidated general purpose financial report of the Group for the financial year ended 30 June 2023 was authorised for issue in accordance with a resolution of the directors on 14 August 2023. This general purpose financial report: – Has been prepared in accordance with Australian Accounting Standards and other authoritative pronouncements of the Australian Accounting Standards Board and the Corporations Act 2001. The financial statements comply with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board. – Has been prepared on a going concern and accruals basis and is based on the historical cost convention, except for derivative financial instruments, debt and equity financial assets, and contingent consideration that have been measured at fair value. – Is presented in Australian dollars with all amounts rounded to the nearest hundred thousand dollars unless otherwise stated, in accordance with ASIC (Rounding in Financial/Directors’ Reports) Instrument 2016/191 issued by the Australian Securities and Investment Commission. – Has been prepared by consistently applying all accounting policies to all the financial years presented, unless otherwise stated. – The consolidated financial statements provide comparative information in respect of the previous period. Where there has been a change in the classification of items in the financial statements for the current period, the comparative for the previous period has been reclassified to be consistent with the classification of that item in the current period. Key judgements and estimates In the process of applying the Group’s accounting policies, management has had to make judgements, estimates and assumptions about future events that affect the reported amounts of assets and liabilities, revenue and expenses. These estimates and judgements incorporate the impact of the ongoing uncertainties associated with material business risks. The reasonableness of these estimates and underlying assumptions are reviewed on an ongoing basis. Actual results may differ from these estimates. The areas involving a higher degree of judgement or complexity, or areas where assumptions and estimates are significant to the financial statements are found in the following notes: Note 2 – Revenue from contracts with customers Note 3 – Expenses Note 5 – Taxation Note 9 – Petroleum assets Note 10 – Exploration and evaluation assets Note 11 – Intangible assets Note 13 – Provisions Note 14 – Leases Climate change In preparing the Financial Report, management has considered the impact of climate change and current climate-related legislation. Beach is committed to managing climate risk and delivering a sustainable business model in a low-carbon world. Beach reports on its climate strategy, annual emissions and emissions targets in the Beach sustainability report which Beach has published annually since 2017 which form key elements of the Financial Stability Board’s Task Force on Climate-Related Disclosures (TCFD) recommendations on climate-related financial disclosures. Beach is targeting a 35% emissions intensity reduction by 2030 (against 2018 levels) which is aligned with the legislated changes in the Safeguard Mechanism (SM) and has an aspiration to reach net zero Scope 1 and 2 emissions by 2050. 77 Notes to the Financial Statements Notes to and forming part of the Financial Statements for the financial year ended 30 June 2023 The SM applies to all facilities with Scope 1 (direct) emissions of at least 100,000 tonnes of CO2-equivalent per annum and requires them to keep their emissions at or below a ‘baseline threshold’. Under legislated changes to the SM which took effect on 1 July 2023, there will be a reduction in annual baseline for SM facilities of 4.9% through to FY30 with Beach’s operated and non-operated facilities at Moomba, Otway, Beharra and Waitsia (once in operation) currently expected to be impacted. Beach has assumed for the purposes of these calculations that from FY30 a new decline rate will be imposed at 3.25% to end-of-asset life post FY30. A new tradable credit, called a ‘Safeguard Mechanism Credit’ (SMC), will be introduced, which arises when a facility exceeds its baseline. These can be sold to other facilities subject to the SM to allow them to meet their baseline targets. In addition to SMCs, entities will be able to purchase Australian Carbon Credit Units (ACCUs), with Government-held ACCUs being available for purchase at a capped price of $75 per tonne CO2-equivalent (increasing at CPI plus 2% per year). The estimated impacts of climate change may be assessed through a range of economic and climate-related policies and scenarios, as reported in the Beach sustainability report. This includes market supply and demand profiles, carbon emissions reduction profiles, legislative impacts and technological impacts, all of which are affected by the global demand profile of the economy as a whole. The financial impact of the SM to either create an asset, where a facility is below its emissions baseline, or a liability, where the facility operates above its baseline, is included in Beach’s economic modelling of projects and valuation of the portfolio as a whole. Beach uses its approved ACCU price to value SM and ACCU generation financial impacts. The energy transition is expected to bring volatility in commodity prices. This may result in scenarios of lower prices through demand destruction and conversely structurally higher commodity prices through demand and supply dynamics. The current estimates and forecasts used by the Group are in accordance with current enacted climate-related legislation and policy. In accordance with Australian Accounting Standards, Beach’s financial statements are based on reasonable and supportable assumptions that represents the Group’s current best estimate of the range of economic conditions that may exist in the foreseeable future. The impacts of climate change and sustainability-related matters have been considered in the significant judgements and key estimates in a number of areas in the Financial Report, including: – asset carrying values for petroleum assets and exploration and evaluation assets through determination of valuations considered for impairment – refer notes 9 and 10; – restoration obligations, including the timing of such activities – refer note 13; and – deferred taxes, primarily related to asset carrying values and restoration obligations – refer note 5; Beach continues to monitor climate-related policy and its impact on the Financial Report. 78 Going concern The Group ended FY23 with $219 million in cash, drawn debt of $385 million and net working capital of $226 million (current assets less current liabilities). Available liquidity was $434 million, comprising $219 million in cash and $215 million in undrawn debt facilities. Management has prepared cash flow forecast scenarios that represent reasonably possible downside scenarios relating to the business from potential economic scenarios that could arise over the next 12 months, which have been reviewed by the directors. These forecasts demonstrate that the Group has sufficient cash, other liquid resources and undrawn credit facilities which along with the flexibility to remove or defer certain discretionary operating and capital expenditures will enable the Group to meet its obligations as they fall due. As such the directors considered it appropriate to adopt the going concern basis of accounting in preparing the full year financial statements. Basis of consolidation The consolidated financial statements are those of Beach and its subsidiaries (detailed in Note 22). Subsidiaries are those entities that Beach controls as it is exposed, or has rights, to variable returns from its involvement with the subsidiary and has the ability to affect those returns through its power over the subsidiary. In preparing the consolidated financial statements, all transactions and balances between Group companies are eliminated on consolidation, including unrealised gains and losses on transactions between Group companies. Where unrealised losses on intra-group asset sales are reversed on consolidation, the underlying asset is also tested for impairment from a Group perspective. Profit or loss and other comprehensive income of subsidiaries acquired or disposed of during the year are recognised from the date Beach obtains control for acquisitions and the date Beach loses control for disposals, as applicable. The acquisition of businesses is accounted for using the acquisition method of accounting. Foreign currency Both the functional and presentation currency of Beach is Australian dollars. Some subsidiaries have different functional currencies which are translated to the presentation currency. Transactions in foreign currencies are initially recorded in the functional currency by applying the exchange rate ruling at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are retranslated at the foreign exchange rate ruling at the reporting date. Foreign exchange differences arising on translation are recognised in the profit or loss. Non monetary assets and liabilities that are measured in terms of historical cost in a foreign currency are translated using the exchange rate at the date of the initial transaction. Non monetary assets and liabilities denominated in foreign currencies that are stated at fair value are translated to the functional currency at foreign exchange rates ruling at the dates the fair value was determined. Foreign exchange differences that arise on the translation of monetary items that form part of the net investment in a foreign operation are recognised in equity in the consolidated financial statements. Revenues, expenses and equity items of foreign operations are translated to Australian dollars using the exchange rate at the date of transaction while assets and liabilities are translated using the rate at balance date with differences recognised directly in the Foreign Currency Translation Reserve. Beach Energy Limited Annual Report 2023 Adoption of new and revised accounting standards In the current year, the Group has adopted all of the new and revised Standards and Interpretations issued by the Australian Accounting Standards Board that are relevant to its operations and effective for the current annual reporting period. Information on relevant new standards is provided below, with no immediate material impact on the Group’s consolidated financial statements. iii) AASB 2023-2 Amendments to Australian Accounting Standards – International Tax Reform – Pillar Two Model Rules The AASB has issued AASB 2023-2, which provides temporary relief from accounting for deferred taxes arising from the Organisation for Economic Co-operation and Development’s (OECD’s) international tax reform. The amendments will introduce a mandatory temporary exception to accounting for deferred taxes arising from the implementation of the Pillar Two model rules published by the OECD; and targeted disclosure requirements to help financial statement users better understand an entity’s exposure to income taxes arising from the reform, particularly in periods before legislation implementing the rules is in effect. This Standard applies to annual periods beginning on or after 1 January 2023 that end on or after 30 June 2023 and is not expected to have a material impact on the Group’s annual consolidated financial statements. iv) International sustainability standards In June 2023, the International Sustainability Standards Board (ISSB) issued two new standards in response to the demand for better information about sustainability related matters as detailed below: – IFRS S1 General Requirements of Sustainability-related Financial Information, the objective of which is to require entities to provide all material information about the entity’s exposure to sustainability-related risks and opportunities that is useful to users of general-purpose financial reporting in making decisions about whether to provide economic resources to the entity. – IFRS S2 Climate-related Disclosures, the objective of which is to require entities to provide information about their exposure to climate-related risks and opportunities. Following consultation in the second half of calendar 2023, detailed disclosure standards will be formally established by the AASB with the intention that the Australian standards will be aligned as far as practicable with the final standards developed by the ISSB. The Standards once issued are expected to be effective for annual reporting periods beginning or after 1 January 2024 with transitional relief expected to be provided in relation to some requirements. The Group is monitoring the development of the standards by AASB and working through the expected requirements of the new standards and the impacts on the Group’s annual consolidated financial statements based on the final standards issued by the ISSB. Several other amendments to standards and interpretations will apply on or after 1 July 2023, and have not yet been applied, however they are not expected to impact the Group’s annual consolidated financial statements. i) Amendments to AASB 116 – Property, Plant and Equipment: Proceeds before intended use The amendment prohibits entities from deducting from the cost of an item of property, plant and equipment (“PP&E”), any proceeds of the sale of items produced while bringing that asset to the location and condition necessary for it to be capable of operating in the manner intended by management. Instead, an entity recognises the proceeds from selling such items, and the costs of producing those items, in profit or loss. ii) Amendments to AASB 137 – Onerous Contracts – Costs of Fulfilling a contract The amendments provide clarification on which costs an entity needs to include when assessing whether a contract is onerous or loss-making. The amendments apply a ‘directly related cost approach’. These amendments have not had a significant or immediate impact on the Group’s annual consolidated financial statements. Standards, amendments, and interpretations to existing standards that are not yet effective and have not been adopted early by the Group At the date of authorisation of these financial statements, certain new standards, amendments and interpretations to existing standards have been published but are not yet effective, and have not been adopted early by the Group in preparing these consolidated financial statements. Management anticipates that all of the relevant pronouncements will be adopted in the Group's accounting policies for the first period beginning after the effective date of the pronouncement. The Group’s assessment of the impact of these new standards, amendments to standards and interpretations is set out below. i) Amendments to AASB 112 – Deferred Tax related to Assets and Liabilities arising from a Single Transaction The amendments narrow the scope of the initial recognition exception under AASB 112, so that it no longer applies to transactions that give rise to equal taxable and deductible temporary differences. These amendments apply from 1 July 2023 and are not expected to have a material impact on the Group’s annual consolidated financial statements. ii) Amendments to AASB 101 – Classification of Liabilities as Current or Non-current The amendments clarify that liabilities are classified as either current or non-current depending on the rights that exist at the end of the reporting period. Classification is unaffected by the entity’s expectations or events after the reporting date (e.g. the receipt of a waver or a breach of covenant). The amendments also clarify what it means when it refers to the ‘settlement’ of a liability. These amendments apply from 1 July 2024 and It is yet to be determined what the impact on the Group would be as a result of this amendment to the standard. 79 Notes to the Financial Statements Notes to and forming part of the Financial Statements for the financial year ended 30 June 2023 RESULTS FOR THE YEAR This section explains the results and performance of the Group including additional information about those individual line items in the financial statements most relevant in the context of the operations of the Group, including accounting policies that are relevant for understanding the items recognised in the financial statements and an analysis of the Group’s result for the year by reference to key areas, including operating segments, revenue, expenses, employee costs, taxation and earnings per share. 1. Operating segments The Group has identified its operating segments to be its South Australian, Western Australian, Victorian and New Zealand interests based on the different geographical regions and the similarity of assets within those regions. This is the basis on which internal reports are provided to the Chief Executive Officer for assessing performance and determining the allocation of resources within the Group. The Group operates primarily in one business, namely the exploration, development and production of hydrocarbons. Revenue is derived from the sale of gas and liquid hydrocarbons. Gas sales contracts are spread across major Australian and New Zealand energy retailers and industrial users with liquid hydrocarbon product sales being made to major multi-national energy companies based on international market pricing. Details of the performance of each of these operating segments for the financial years ended 30 June 2023 and 30 June 2022 are as follows: SA WA Victoria New Zealand Total 2023 $million 2022 $million 2023 $million 2022 $million 2023 $million 2022 $million 2023 $million 2022 $million 2023 $million 2022 $million 1,093.2 1,219.2 41.7 32.6 338.5 317.2 143.5 180.1 1,616.9 1,749.1 584.4 (249.5) 736.1 (227.1) 334.9 509.0 29.5 (12.1) 17.4 20.3 (9.5) 10.8 250.4 (119.4) 131.0 235.6 (111.0) 124.6 97.2 (19.2) 78.0 126.4 (17.3) 109.1 961.5 (400.2) 1,118.4 (364.9) 561.3 29.5 10.3 (27.0) (14.8) 559.3 (158.5) 400.8 753.5 22.3 12.0 (13.5) (57.7) 716.6 (215.8) 500.8 3,046.1 2,535.2 856.2 603.1 1,569.7 1,387.6 220.1 243.9 5,692.1 4,769.8 685.6 538.1 75.9 19.8 417.3 361.8 120.4 121.2 1,229.2 1,040.9 202.8 5,894.9 332.3 5,102.1 717.8 2,017.0 521.3 1,562.2 64.3 491.7 556.0 66.2 288.6 354.8 37.2 206.6 243.8 1.0 122.2 123.2 17.2 253.3 270.5 26.1 286.5 312.6 0.3 15.1 15.4 – 9.7 9.7 119.0 966.7 93.3 707.0 1,085.7 800.3 3.7 6.7 1,089.4 807.0 Segment revenue Sales revenue(1) Segment results Gross segment result before depreciation, amortisation Depreciation and amortisation Other revenue Other income Net financing costs Other expenses Profit/(loss) before tax Income tax expense Net profit/(loss) after tax Segment assets Total corporate and unallocated assets Total consolidated assets Segment liabilities Total corporate and unallocated liabilities Total consolidated liabilities Additions and acquisitions of non-current assets Exploration and evaluation assets Petroleum assets Total corporate and unallocated assets Total additions and acquisitions of non-current assets (1) During the year revenue from three customers amounted to $1,046 million (2022: $1,220 million from three customers) arising from sales from SA, WA, Victoria and New Zealand segments. 80 Beach Energy Limited Annual Report 2023 Non-current assets Australia New Zealand Total 2023 $million 5,046.7 2022 $million 4,203.4 2023 $million 178.1 2022 $million 202.9 2023 $million 5,224.8 2022 $million 4,406.3 2. Revenue from contracts with customers and other income Revenue from contracts with customers is recognised in the income statement when the performance obligations are considered met, which is when control of the hydrocarbon products or services provided are transferred to the customer. Revenue is recognised at an amount that reflects the consideration the Group expects to be entitled to, net of goods and services tax or similar taxes. Product sales Sales revenue is recognised using the “sales method” of accounting. The sales method results in revenue being recognised based on volumes sold under contracts with customers, at the point in time where performance obligations are considered met. Generally, regarding the sale of hydrocarbon products, the performance obligation will be met when the product is delivered to the specified measurement point (gas) or point of loading/unloading (liquids). The Group’s sales of crude oil, liquefied natural gas, ethane, condensate, LPG, and in some contractual arrangements, natural gas, are based on market prices. In contractual arrangements with market base pricing, at the time of the delivery, there is only a minimal risk of a change in transaction price to be allocated to the product sold. Accordingly, at the point of sale where there is not a significant risk of revenue reversal relative to the cumulative revenue recognised, there is no constraining of variable consideration. Where the sales price is not final at the point the performance obligations are met, any subsequent measurement of these provisionally priced sales is not revenue from customers and has been recognised as other sales revenue. Contract liabilities and contract assets A contract liability for deferred revenue is recorded for obligations under sales contracts to deliver natural gas in future periods for which payment has already been received. Where the period between when payment is received and performance obligations are considered met, is more than 12 months, an assessment will be made for whether a significant financing component is required to be accounted for. Deferred revenue liabilities unwind as “revenue from contracts with customers”, with reference to the performance obligation, and if a significant financing component associated with deferred revenue exists, an interest expense will also be recognised over the life of the contract. On acquisition of the Lattice and Toyota Tsusho interests, pre-existing revenue contracts were fair valued, resulting in contract assets and liabilities being recognised. Both the contract assets and liabilities represent the differential in contract pricing and market price, and will be realised as performance obligations are considered met in the underlying revenue contract. To the extent a contract asset or liability represents the fair value differential between contract price and market price, it will be unwound through “other operating revenue or expense”. Net contract assets have decreased by $7.1 million to $31.0 million, with $11.0 million included in other expense and $0.4 million in FCTR less $3.5 million unwind of discount included in finance expenses. (a) Revenue Crude oil Sales gas and ethane Liquefied petroleum gas Condensate Gas and gas liquids Revenue from contracts with customers Crude oil – revaluation of provisionally priced sales Sales Revenue (1) Other operating revenue Total revenue (1) Provisionally priced oil sales revenue recorded as a receivable at 30 June 2023 was nil (FY22 $53.4 million). Consolidated 2023 $million 2022 $million 603.6 677.3 146.8 189.2 1,013.3 1,616.9 – 1,616.9 29.5 1,646.4 625.7 673.8 202.0 214.3 1,090.1 1,715.8 33.3 1,749.1 22.3 1,771.4 81 Notes to the Financial Statements Notes to and forming part of the Financial Statements for the financial year ended 30 June 2023 2. Revenue from contracts with customers and other income (continued) (b) Other income Gain on sale of joint operations interests Gain on sale of non-current assets Other income related to joint venture lease recoveries Government grants received Foreign exchange gains Other Total other income 3. Expenses Consolidated 2023 $million 2022 $million 1.0 – 3.8 0.7 2.2 2.6 10.3 0.7 0.3 3.3 0.7 6.4 0.6 12.0 The Group’s significant expenses in operating the business are described below split between cost of sales and other expenses including impairment and corporate and other costs. (a) Cost of sales Field operating costs Tariffs and tolls Royalties Total operating costs Depreciation and amortisation of petroleum assets (Note 9) Depreciation of leased assets (Note 14) Third party oil and gas purchases Decrease/(increase) in product inventory Total cost of sales (b) Other expenses Exploration expense Restoration expense Loss on sale of non-current assets Depreciation of leased assets (Note 14) Reversal of accrued acquisition costs Unwind of acquired contract assets and liabilities Provision for legal costs related to shareholder class actions Corporate expenses (1) Other expenses Total other expenses Consolidated 2023 $million 2022 $million 281.9 94.1 120.9 496.9 391.7 8.4 190.4 (31.8) 1,055.6 0.1 – 0.5 3.2 (16.8) 11.0 – 16.8 14.8 14.8 255.8 94.5 182.2 532.5 357.1 7.6 99.2 (0.8) 995.6 (0.2) 29.5 0.2 3.6 – 4.5 5.0 15.1 57.7 57.7 (1) Includes depreciation of property, plant and equipment and amortisation of software costs of $8.9 million (FY22 $7.9 million) as shown in Note 8 and 11, and share based payments expense of $2.3 million (FY22 $2.1 million). 82 Beach Energy Limited Annual Report 2023 4. Employee benefits Provision is made for the Group's employee benefits liability arising from services rendered by employees to the end of the reporting period. These benefits include wages, salaries, annual leave and long service leave. Where these benefits are expected to be settled within 12 months of the reporting date, they are measured at the amounts expected to be paid when the liabilities are settled. Expenses for non-vesting personal leave are recognised when the leave is taken and are measured at the rates paid or payable. Liabilities for long service leave and annual leave that is not expected to be taken wholly before 12 months after the end of the reporting period in which the employee rendered the related service, are recognised and measured as the present value of the estimated future cash outflows to be made in respect of employees’ services up to the reporting date. The obligation is calculated using expected future increases in wage and salary rates, experience of employee departures and periods of service. The estimated future payments have been discounted using Australian corporate bond rates. The obligations are presented as current liabilities in the statement of financial position if the Group does not have the unconditional right to defer settlement for at least 12 months after the reporting date, regardless of when the actual settlement is expected to occur. Superannuation commitments – Each employee nominates their own superannuation fund into which Beach contributes compulsory superannuation amounts based on a percentage of their salary. Termination benefits – Termination benefits may be payable when employment is terminated before the normal retirement date, without cause, or when an employee accepts voluntary redundancy in exchange for these benefits. Beach recognises termination benefits when it is demonstrably committed to making these payments. Equity settled compensation Employee Incentive Plan – The Group operates an Employee Incentive Plan, approved by shareholders. Shares are allotted to employees under this plan at the Board’s discretion. Shares acquired by employees are funded by interest free non-recourse loans for a term of 10 years which are repayable on cessation of employment with the consolidated entity or expiry of the loan term. The fair value of the equity to which employees become entitled is measured at grant date and recognised as an expense over the vesting period with a corresponding increase in equity. The fair value of shares issued is determined with reference to the latest ASX share price. Rights are valued using an appropriate valuation technique such as the Binomial or Black-Scholes Option Pricing Models which takes into account the vesting conditions. The following employee shares are currently on issue Balance as at 30 June 2021 Loans repaid during 2022 financial year Balance as at 30 June 2022 Loans repaid during 2023 financial year Balance as at 30 June 2023 Number 1,387,438 (709,838) 677,600 (677,600) – No new shares were issued to employees during the financial year, pursuant to this plan. The closing ASX share price of Beach fully paid ordinary shares at 30 June 2023 was $1.35 as compared to $1.725 as at 30 June 2022. Employee Share Plan – The group operates an employee share plan, approved by shareholders. Employees who buy shares under the Plan will have those shares matched by Beach, provided any relevant conditions determined by the Board are satisfied. Eligible Employees are employees of the Group, other than a non-executive director and any other person determined by the Board as ineligible to participate in the Plan. The Board has the discretion to set an annual limit on the value of shares that participants may purchase under the Plan, not exceeding $5,000. Purchased Shares have been acquired periodically at the prevailing market price. Participants pay for their Purchased Shares using their own funds which may include salary sacrifice. To receive Matched Shares, a participant must satisfy the conditions determined by the Board at the time of the invitation, including remaining an employee throughout the three year vesting period. Details of shares purchased and utilised under this plan are detailed in Note 19. Incentive Rights – The Group operates an Executive Incentive Plan (EIP) providing both Short Term Incentives (STIs) and Long Term Incentives (LTIs). The STI is part of ‘at risk’ remuneration offered to senior executives. It measures individual and Company performance over a 12 month period coinciding with Beach's financial year. It is provided in equal parts of cash and equity that may or may not vest subject to additional retention conditions. It is offered annually to senior executives at the discretion of the Board. The LTI is an equity based ‘at risk’ incentive plan. The LTI is intended to reward efforts and results that promote long term growth in shareholder value or total shareholder return (TSR). LTIs are offered to senior executives at the discretion of the Board. The fair value of performance rights issued are recognised as an employee benefits expense with a corresponding increase in equity. The fair value of the performance rights are measured at grant date and recognised over the vesting period during which the senior executives become entitled to the performance rights. The fair value of the STIs and Retention Rights is measured using the Black-Scholes Option Pricing Model and the fair value of the LTIs is measured using Monte Carlo simulation, taking into account the terms and conditions upon which these rights were issued. 83 Notes to the Financial Statements Notes to and forming part of the Financial Statements for the financial year ended 30 June 2023 4. Employee benefits (continued) Details of the key assumptions used in determining the valuation of unlisted performance rights issued during FY23 are outlined below. 2021 LTI Rights 2022 LTI Rights 2021 STI Rights 2021 STI Rights 2022 Retention Rights FY23 ESP (1) Grant date 12 Oct 2022 2 Feb 2023 21 Nov 2022 21 Nov 2022 Vesting date Expiry date Share price at grant date (A$) Exercise price (A$) Expected volatility (average) Vesting Period (years) Risk free rate Dividend yield Number of securities issued 1 Dec 2024 1 Dec 2025 30 Nov 2026 30 Nov 2027 1.46 Nil 53.4% 2.8 3.05% 1.37% 2,265,837 1.51 Nil 50.9% 2.1 3.32% 1.32% 168,598 Fair value of security at grant date (A$) Total fair value at grant date 0.66 111,275 0.60 1,359,502 1 Jul 2023 n/a 1.70 Nil n/a 0.6 n/a 1.18% 178,149 1.68 299,290 1 Jul 2024 n/a 1.70 Nil n/a 1.6 n/a 1.18% 178,144 1.66 295,719 2 Feb 2023 1 Jul 2025 n/a 1.46 Nil n/a 2.4 n/a Up to 30 Jun 2023 1 Jul 2025 n/a 1.35 – 1.82 Nil n/a 2.0 – 2.9 n/a 1.37% 1.10% – 1.48% 575,701 2,331,378 1.41 3,287,243 1.31 – 1.76 855,031 (1) Matched Share Rights under the Employee Share Plan are acquired periodically throughout the year. Details show the range of valuation inputs during the year. Details of the key assumptions used in determining the valuation of unlisted performance rights issued during FY22 are outlined below. 2020 LTI Rights 2021 LTI Rights 2021 LTI Rights 2021 LTI Rights FY22 ESP (1) Grant date Vesting date Expiry date Share price at grant date (A$) Exercise price (A$) Expected volatility (average) Vesting Period (years) Risk free rate Dividend yield Number of securities issued 30 Sep 2021 1 Dec 2023 30 Nov 2025 1.50 Nil 52.7% 2.2 0.25% 1.34% 87,203 1 Dec 2024 31 Dec 2021 30 Jun 2022 31 Mar 2022 Up to 30 Jun 2022 1 Jul 2024 1 Dec 2024 1 Dec 2024 n/a 30 Nov 2026 30 Nov 2026 30 Nov 2026 1.05 – 1.73 1.73 Nil Nil n/a 50.4% 2.0 – 2.9 2.4 3.19% n/a 1.16% 1.16% – 1.90% 709,379 1.26 Nil 50.8% 2.9 2.26% 1.59% 2,112,784 1.56 Nil 52.9% 2.7 2.18% 1.29% 958,735 327,702 Fair value of security at grant date (A$) Total fair value at grant date 0.82 71,506 0.69 1,457,821 0.86 824,512 1.05 344,087 0.99 – 1.69 956,810 (1) Matched Share Rights under the Employee Share Plan are acquired periodically throughout the year. Details show the range of valuation inputs during the year. Movements in unlisted performance rights are set out below: Balance at beginning of period Issued during the period Forfeited during the period Vested/Exercised during the period Balance at end of period 84 Consolidated 2023 number 2022 number 8,184,339 7,433,153 4,195,803 5,697,807 (2,474,396) (3,346,082) (507,050) (1,600,907) 7,433,153 10,149,514 Beach Energy Limited Annual Report 2023 5. Taxation Taxation on the profit or loss for the year comprises current and deferred tax. Taxation is recognised in profit or loss except to the extent that it relates to items recognised directly in equity or other comprehensive income. Current tax is the expected tax payable on the taxable income for the year, using tax rates and laws enacted or substantively enacted at the reporting date, and any adjustments to tax payable in respect of previous years. Deferred tax is determined using the statement of financial position approach on temporary differences arising between the tax bases of assets and liabilities and their carrying amounts in the statement of financial position. Deferred tax assets are recognised to the extent that it is probable that future taxable profits will be available against which the temporary differences or unused tax losses and tax offsets can be utilised. Deferred tax is not recognised for temporary differences arising from goodwill or from the initial recognition of assets and liabilities (other than a business combination) in a transaction that affects neither accounting profit nor taxable income. Deferred tax assets and liabilities are measured at the tax rates that are expected to be applied when the asset is realised or the liability is settled, based on the laws that have been enacted or substantively enacted at the reporting date. Current and deferred tax assets and liabilities are offset when there is a legally enforceable right to offset and when the tax balances are related to taxes levied by the same tax authority and the entity intends to settle its tax assets and liabilities on a net basis. Petroleum Resource Rent Tax (PRRT) PRRT is considered, for accounting purposes, to be a tax based on income. Accordingly, current and deferred PRRT expense is measured and disclosed on the same basis as income tax. 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 for PRRT can be recognised in the statement of financial position. Australian income tax consolidation Beach and its wholly owned Australian subsidiaries are consolidated for Australian income tax purposes with Beach responsible for recognising the current and deferred tax assets and liabilities for the income tax consolidated group. Beach is responsible for recognising the current tax liability, current tax assets and deferred tax assets arising from unused tax losses and credits for the income tax consolidated group. The Group has applied the separate taxpayer approach in determining the appropriate amount of current taxes and deferred taxes to allocate to members of the tax consolidated group. Beach has entered into a tax sharing agreement with its wholly owned subsidiaries whereby each company in the Group contributes to the income tax payable in proportion to their contribution to the net profit before tax of the tax consolidated group. Goods and services tax Revenues, expenses and assets are recognised net of the amount of goods and services tax (GST), except: – When the GST incurred on a purchase of goods and services is not recoverable from the taxation authority, in which case the GST is recognised as part of the cost of acquisition of the asset or as part of the expense item as applicable; and – Receivables and payables, which are stated with the amount of GST included. The net amount of GST recoverable from, or payable to, the taxation authority is included as part of receivables or payables in the Statement of Financial Position. Cash flows are included in the Consolidated Statement of Cash Flows on a gross basis. Commitments and contingencies are disclosed net of the amount of GST recoverable from, or payable to, the taxation authority. 85 Notes to the Financial Statements Notes to and forming part of the Financial Statements for the financial year ended 30 June 2023 5. Taxation (continued) (a) Income tax expense Income tax recognised in the statement of profit or loss of the Group is as follows: Recognised in the statement of profit or loss Current tax expense Current year Adjustments for prior years Total current tax expense Deferred tax expense Origination and reversal of temporary differences Adjustments for prior years Total deferred tax expense Total income tax expense Consolidated 2023 $million 2022 $million 96.5 (32.7) 63.8 65.2 29.5 94.7 158.5 157.0 (3.8) 153.2 56.2 6.4 62.6 215.8 (b) Numerical reconciliation between tax expense and prima facie tax expense A reconciliation between income tax expense calculated on profit before tax to income tax expense included in the statement of profit or loss: Accounting profit before income tax Prima facie tax on accounting profit before tax at 30% Adjustment to income tax expense due to: Non-deductible expenditure Impact of tax rates applicable outside Australia Non assessable income Adjustments for prior years Other Income tax expense reported in the Statement of Profit or Loss Consolidated 2023 $million 559.3 167.8 2022 $million 716.6 215.0 1.3 (1.6) (4.3) (3.2) (1.5) 158.5 0.9 (2.7) – 2.6 – 215.8 86 Beach Energy Limited Annual Report 2023 (c) Income tax related to items charged or credited to equity ($million) Share based equity FCTR (d) Deferred tax assets and liabilities ($million) Current financial year Oil & Gas Assets Provisions Employee benefits Tax Losses Leases Other Items Tax assets/(liabilities) Set-off of tax Net deferred tax assets/(liabilities) Consolidated 2023 $million 2022 $million (0.2) (1.0) (0.2) 2.4 Assets Liabilities Net 2023 $million 2022 $million 2023 $million 2022 $million 2023 $million 2022 $million – 309.6 7.3 0.4 7.6 8.5 333.4 – 274.7 6.6 1.3 9.9 5.5 298.0 (333.4) – (298.0) – (509.7) – – – (7.1) (17.6) (534.4) 333.4 (201.0) (346.7) – – – (9.5) (48.2) (404.4) 298.0 (106.4) (509.7) 309.6 7.3 0.4 0.5 (9.1) (201.0) – (201.0) (346.7) 274.7 6.6 1.3 0.4 (42.7) (106.4) – (106.4) (e) Deferred tax assets have not been recognised in respect of the following items: Revenue losses – non-Australian Capital losses Petroleum rights Petroleum Resource Rent Tax, net of income tax Total Consolidated 2023 $million 2.6 28.7 43.4 1,810.7 1,885.4 2022 $million 2.6 28.7 43.4 1,661.6 1,736.3 Future Tax Developments We are monitoring the Organisation for Economic Co-operation and Development’s (OECD) Two Pillar Solution to address the Tax Challenges Arising from the Digitalisation of the Economy, which proposes to apply a 15% global minimum tax. On 9 May 2023, the Australian Government announced, as part of the 2023/24 Federal Budget, that it will adopt legislation to implement the OECD Global Anti-Base Erosion (GloBE) Pillar Two rules. Legislation is expected to be enacted in 2023 with application to Beach from 1 July 2024. We are in the process of evaluating the cash tax and accounting implications of the Pillar Two global minimum tax rules. Recognition of any impact will only occur once legislation has been substantively enacted. 87 Notes to the Financial Statements Notes to and forming part of the Financial Statements for the financial year ended 30 June 2023 6. Earnings per share (EPS) The Group presents basic and diluted EPS for its ordinary shares. Basic EPS is calculated by dividing the profit or loss attributable to ordinary shareholders of the Company by the weighted average number of ordinary shares outstanding during the year. Diluted EPS is determined by adjusting the statement of profit or loss attributable to ordinary shareholders and the weighted average number of ordinary shares for the dilutive effect, if any, of outstanding share rights which have been issued to employees. Earnings after tax used in the calculation of EPS is as follows: Basic EPS and Diluted EPS 2023 $million 400.8 2022 $million 500.8 Weighted average number of ordinary shares and potential ordinary shares used in the calculation of EPS is as follows: Basic EPS Share rights Diluted EPS Calculation of EPS is as follows: Basic earnings per share (cents per share) Diluted earnings per share (cents per share) 2023 Number 2022 Number 2,279,710,830 1,251,628 2,279,696,899 3,350,862 2,280,962,458 2,283,047,761 17.58¢ 17.57¢ 21.97¢ 21.94¢ 5,832,053 (FY22 2,421,192) potential ordinary shares relating to performance rights that were not considered dilutive during the period as vesting would not have occurred based on the status of the required vesting conditions at the end of the relevant reporting period. Accordingly, these have been excluded from the calculation of diluted EPS. 88 Beach Energy Limited Annual Report 2023 CAPITAL EMPLOYED This section details the investments made by the Group in exploring for and developing its petroleum business including inventories, property, plant and equipment, petroleum assets, joint operations, leases and any related restoration provisions as well as an assessment of asset impairment and details of future commitments. 7. Inventories Inventories are stated at the lower of cost and net realisable value. Net realisable value is the estimated selling price in the ordinary course of business, less the estimated costs of completion and selling expenses. Cost is determined as follows: (i) Drilling and maintenance stocks, which include plant spares, consumables, maintenance and drilling tools used for ongoing operations, are valued at weighted average cost; and (ii) Petroleum products, which comprise extracted crude oil, liquefied petroleum gas, condensate and naphtha stored in tanks and pipeline systems and process sales gas and ethane stored in sub-surface reservoirs, are valued using the absorption cost method. Petroleum products Drilling and maintenance stocks Less provision for obsolescence Total current inventories at lower of cost and net realisable value Petroleum products included above which are stated at net realisable value 8. Property, plant and equipment (PPE) Consolidated 2023 $million 2022 $million 74.0 95.4 (8.2) 161.2 – 40.4 68.7 (7.7) 101.4 – PPE is measured at cost less depreciation and impairment losses. The carrying amount of PPE is reviewed bi-annually for impairment triggers. The cost of PPE constructed within the Group includes the cost of materials, direct labour, borrowing costs and an appropriate proportion of fixed and variable overheads. 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 statement of profit or loss during the financial period in which they are incurred. The assets residual values and useful lives are reviewed, and adjusted if appropriate, at each reporting date. Gains and losses on disposals are determined by comparing proceeds with the carrying amount and are included in the profit or loss. The depreciable amount of all PPE is depreciated using a straight line basis over their useful lives commencing from the time the asset is held ready for use. The depreciation rates used in the current and previous period for each class of depreciable asset are between 11–33%. Property, plant and equipment Plant and equipment Plant and equipment under construction Less accumulated depreciation Total property, plant and equipment Reconciliation of movement in property, plant and equipment: Balance at beginning of financial year Additions Depreciation expense Total property, plant and equipment Consolidated 2023 $million 2022 $million 15.5 1.0 (12.5) 4.0 6.2 0.2 (2.4) 4.0 13.3 3.0 (10.1) 6.2 8.6 – (2.4) 6.2 89 Notes to the Financial Statements Notes to and forming part of the Financial Statements for the financial year ended 30 June 2023 9. Petroleum assets Petroleum assets are stated at cost less accumulated depreciation and impairment charges. They include initial cost, with an appropriate proportion of fixed and variable overheads, to acquire, construct, install or complete production and infrastructure facilities such as pipelines and platforms, capitalised borrowing costs, transferred exploration and evaluation assets and development wells. Subsequent capital costs, including major maintenance, are included in the asset’s carrying amount 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. The depreciable amount of all onshore production facilities, field and other equipment excluding freehold land is depreciated using a straight line basis over the lesser of their useful lives and the life of proved and probable reserves commencing from the time the asset is held ready for use. Offshore production facilities and field equipment are depreciated based on a units of production method using proved and probable reserves. The depreciation rates used in the current and previous period for each class of depreciable asset are 1–45% for onshore production facilities, field and other equipment. Subsurface assets are amortised using the units of production method over the life of the area according to the rate of depletion of the proved and probable reserves. Retention of petroleum licences is subject to meeting certain work obligations/commitments as detailed in Note 15. The assets residual values and useful lives are reviewed, and adjusted if appropriate, at each reporting date. Gains and losses on disposals are determined by comparing proceeds with the carrying amount and are included in the profit or loss. Estimates of reserve and resource quantities The estimated quantities of reserves and resources reported by the Group are integral to the calculation of amortisation (depletion) expense and to assessments of possible impairment or impairment reversal. These estimated quantities are based upon interpretations of geological, geophysical and engineering models and assessment of the technical feasibility and commercial viability of production. Beach prepares its reserves and resources estimates in accordance with the 2018 update to the Petroleum Resources Management System sponsored by the Society of Petroleum Engineers, World Petroleum Council, American Association of Petroleum Geologists, Society of Petroleum Evaluation Engineers, Society of Exploration Geoscientists, Society of Petrophysicists and Well Log Analysts and the European Association of Geoscientists & Engineers (SPE-PRMS). The estimates are subject to periodic independent review or audit. All estimates of reserves and resources reported by Beach are prepared by, or under the supervision of, a qualified petroleum reserves and resources evaluator. Over half of Beach's 2P reserves as at 30 June 2023 have been independently audited by Netherland, Sewell & Associates, Inc. in accordance with Beach's reserves policy. Estimates of reserves and resources require assumptions regarding future development and production costs, commodity prices, exchange rates and fiscal regimes. Estimates may change from period to period as the economic assumptions used to prepare the estimates can change from period to period, and as additional geological, geophysical and engineering information becomes available through additional drilling or technical analysis. Estimates are reviewed annually or when there are significant changes in the circumstances impacting specific assets or asset groups. These changes may impact depreciation, asset carrying values, restoration provisions and deferred tax balances. If reserves estimates are revised downwards, earnings could be affected by higher depreciation expense or an immediate write-down of the asset's carrying value. 90 Beach Energy Limited Annual Report 2023 Field land and buildings Land and buildings at cost Less accumulated depreciation Total field land and buildings Reconciliation of movement in field land and buildings: Balance at beginning of financial year Additions Depreciation expense Foreign exchange movement Total field land and buildings Production facilities and field equipment Production facilities and field equipment Production facilities and field equipment under construction Less accumulated depreciation Total production facilities and field equipment Reconciliation of movement in production facilities, field and other equipment: Balance at beginning of financial year Additions Acquisition of assets and joint operation interests (Note 26) Depreciation expense Disposals Foreign exchange movement Total production facilities and field equipment Subsurface assets Subsurface assets at cost Subsurface assets under construction Less accumulated depreciation Total subsurface assets Reconciliation of movement in subsurface assets Balance at beginning of financial year Additions Acquisition of assets and joint operation interests (Note 26) Increase/(decrease) in restoration Borrowing costs capitalised Foreign exchange movement Amortisation expense Disposals Capitalised depreciation of lease assets Total subsurface assets Total petroleum assets Consolidated 2023 $million 2022 $million 81.2 (27.7) 53.5 56.4 – (3.1) 0.2 53.5 81.0 (24.6) 56.4 56.4 2.8 (2.3) (0.5) 56.4 2,288.6 416.3 (1,180.5) 1,524.4 2,210.4 107.7 (1,066.6) 1,251.5 1,251.5 379.3 – (108.2) (0.2) 2.0 1,524.4 1,184.4 150.1 0.9 (78.8) (0.2) (4.9) 1,251.5 5,159.1 591.6 (2,846.5) 2,904.2 4,385.3 633.2 (2,566.9) 2,451.6 2,451.6 590.6 – 132.2 13.2 1.1 (280.6) (5.8) 1.9 2904.2 2,190.8 554.7 0.8 (70.3) 7.5 – (276.3) – 44.4 2,451.6 4,482.1 3,759.5 91 The value in use calculation for the Cooper Basin CGU includes a risked view of contingent resources that is expected to be converted to reserves based on a history of production and resource conversions over a significant period of time with the development cost of these resources included into the NPV calculation and in line with long term asset plans for the ongoing realisation of value from the asset. This is assessed against a carrying value including additional exploration transfers to development aligned to these projected resource conversions. Impairment and impairment reversal indicator modelling In determining whether there is an indicator of impairment, in the absence of quoted market prices, estimates are made regarding the present value of future cash flows for each CGU. These estimates require significant management judgement and are subject to risk and uncertainty, and hence changes in economic conditions can also affect the assumptions used and the rates used to discount future cash flow estimates. Current climate change legislation is also factored into the calculation and future uncertainty around climate change risks continue to be monitored. These risks may include a proportion of a CGU’s reserves becoming incapable of extraction in an economically viable fashion; demand for the Group’s products decreasing, due to policy, regulatory (including carbon pricing mechanisms), legal, technological, market or societal responses to climate change and physical impacts related to acute risks resulting from increased severity of extreme weather events, and those related to chronic risks resulting from longer-term changes in climate patterns. In most cases, the present value of future cash flows is most sensitive to the assumptions outlined below. For impairment reversals, the present value of future cash flows are considered using lower oil price scenarios based on a Monte-Carlo simulation of Reuters Mean and a 10% reduction in life of asset production, assuming production loss under a long-term oil-price constrained environment. Notes to the Financial Statements Notes to and forming part of the Financial Statements for the financial year ended 30 June 2023 9. Petroleum assets (continued) Petroleum assets are assessed for impairment indicators on a cash generating unit (CGU) basis half yearly to determine whether there is an indication of impairment or impairment reversal for those assets which have previously been impaired. Following review of interdependencies between the various operations within the Group, it has been determined that the operational CGUs are Cooper Basin, Perth Basin, Victoria Otway, South Australia Otway, Bass Gas and Kupe. Where the carrying value of a CGU includes goodwill, the recoverable amount of the CGU is estimated regardless of whether there is an indicator of impairment or not. Indicators of impairment and impairment reversals include changes in future selling prices, future costs and reserves and resources. When assessing potential indicators of impairment or reversals the Group models scenarios and a range of possible future commodity prices is considered. If any such indication exists, the asset’s recoverable amount is estimated. The recoverable amount of an asset or CGU is determined as the higher of its value in use and fair value less costs of disposal. Value in use is determined by estimating future cash flows based on reserves and in some cases resources after taking into account the risks specific to the asset and discounting it to its present value using an appropriate discount rate. Fair value less costs of disposal also considers value attributable to additional resource and exploration opportunities beyond reserves based on production plans as well as costs of disposal. If the carrying amount of an asset or CGU exceeds its recoverable amount, the asset or CGU is written down and an impairment loss is recognised in the statement of profit or loss. For assets previously impaired, if the recoverable amount exceeds the carrying amount and the indicators driving the increase in value are sustained for a period of time, the impairment loss is reversed, except in relation to goodwill. The carrying amount of the asset or CGU is increased to the revised estimate of its recoverable amount, but only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depreciation or amortisation, if no impairment loss had been recognised. Future cash flow information used for the recoverable amount calculations is based on the Group’s latest reserves, budget, five-year plan and economic life of field plans which includes information sourced and reviewed from operators of our non-operated interests. The impact of the Safeguard Mechanism through either a carbon price or earning of SMCs on Beach facilities depending on emissions relative to their baseline and the earning of ACCUs on Beach’s interest in the Moomba carbon capture and storage project have been included as part of the recoverable amount calculations for each CGU where applicable. The proposed investments which are required as part of the delivery of the Group’s emissions target of a 35% emissions intensity reduction by 2030 (against 2018 levels) for Scope 1 emissions as well as the ability to pass through any carbon costs incurred to customers are also included as part of the recoverable amount calculations for each applicable CGU. Beach continues to monitor the uncertainty around climate change risks and will reassess its assumptions as the energy transition progresses. 92 Beach Energy Limited Annual Report 2023 In the event that future circumstances vary from these assumptions, the recoverable amount of the Group’s petroleum assets could change materially and result in impairment losses or the reversal of previous impairment losses. Due to the interrelated nature of the assumptions, movements in any one variable can have an indirect impact on others and individual variables rarely change in isolation. Additionally, management can be expected to respond to some movements, to mitigate downsides and take advantage of upsides, as circumstances allow. Consequently, it is impracticable to estimate the indirect impact that a change in one assumption has on other variables and hence, on the likelihood, or extent, of impairments, or reversals of impairments, under different sets of assumptions in subsequent reporting periods. During the period, there were no changes to asset useful lives nor depletion or depreciation rates as a result of climate related risks. If changes are required in the future, these changes will be accounted for on a prospective basis in accordance with Australian accounting standards. Economic assumptions The present value of future cash flows for each CGU were estimated using the assumptions below with reference to external market forecasts at least bi-annually. The assumptions applied have regard to contracted prices and observable market data including forward values, external market analyst’s forecasts, specific target market supply/demand dynamics, substitutable energy/feedstock prices and government intervention policies. For the current financial year, the following assumptions were used in the assessment of the CGU’s recoverable amounts: – Brent oil price (real) of US$79.50/bbl in FY24 and FY25, US$81.50/bbl for FY26, US$78/bbl for FY27 and US$75/bbl for FY28 and beyond. – JKM price (real) average of US$15.07/mmbtu in FY24–FY25, and market consensus from FY26+. – Waitsia LNG prices based on Brent and JKM hybrid formula under the bp LNG SPA. – Uncontracted East Australian Gas prices based on FY24–25 spot price markers for short term spot sales, competitive supply markers from major domestic supply sources in FY24–FY26 and LNG Import netback under oil linked LNG SPAs for FY27 and beyond. – Carbon pricing slope of $45/tCO2e for FY24 increasing to A$61/tCO2e by 2030 then increasing to A$70/tCO2e by 2040 (real) for Australia and NZ$80/tCO2e from FY24 increasing to NZ$138/tCO2e by FY30 and further increasing to NZ$250/tCO2e post 2040 for New Zealand. – A$/US$ exchange rate of 0.68 for FY24-FY26, 0.71 for FY27 and 0.725 for FY28 and beyond. – A$/NZ$ exchange rate of 1.09 for FY24 and 1.10 for FY25 and beyond. – Post-tax real discount rate of 7%. 93 Notes to the Financial Statements Notes to and forming part of the Financial Statements for the financial year ended 30 June 2023 10. Exploration and evaluation assets Expenditure on exploration and evaluation is accounted for in accordance with the area of interest method. Areas of interest are based on a geological area. These costs are only carried forward to the extent that they are expected to be recouped through the successful development or sale of the area or where activities in the area have not yet reached a stage that permits reasonable assessment of the existence of proved and probable hydrocarbon reserves and where the rights to tenure of the area of interest are current. The costs of acquiring interests in new exploration and evaluation licences are capitalised. The costs of drilling exploration wells are initially capitalised pending the results of the well. Costs are expensed where the well does not result in the successful discovery of economically recoverable hydrocarbons and the recognition of an area of interest. Subsequent to the recognition of an area of interest, all further evaluation costs relating to that area of interest are capitalised. Upon approval for the commercial development of an area of interest, accumulated expenditure for the area of interest is transferred to petroleum assets. Area of interest An area of interest (AOI) is defined by Beach as an area defined by major geological structural elements that has a discrete exploration strategy and has largely independent costs for exploration and evaluation from other geological areas. Impairment of exploration and evaluation assets The carrying amounts of the Group’s exploration and evaluation assets are reviewed at each reporting date, to determine whether any of the following indicators of impairment exist: – tenure over the AOI has expired during the period or will expire in the near future, and is not expected to be renewed; or – substantive expenditure on further exploration for, and evaluation of, mineral resources in the specific AOI is not budgeted or planned; or – exploration for, and evaluation of, resources in the specific AOI have not led to the discovery of commercially viable quantities of resources, and the Group has decided to discontinue activities in the specific AOI; or – sufficient data exists to indicate that, although a development is likely to proceed, the carrying amount of the exploration and evaluation asset is unlikely to be recovered in full from successful development or from sale. Where a potential impairment is indicated, assessment is performed using a fair value less costs to dispose method to determine the recoverable amount for each AOI to which the exploration and evaluation expenditure is attributed. This assessment requires management to make certain estimates and apply judgement in determining assumptions as to future events and circumstances, in particular, the assessment of whether economic quantities of reserves or resources have been found. Any such estimates and assumptions may change as new information becomes available. If, after having capitalised expenditure under the policy, the Group concludes that it is unlikely to recover the expenditure by future exploitation or sale, then the relevant capitalised amount will be written off to the statement of profit or loss. Retention of exploration assets is subject to meeting certain work obligations/exploration commitments as detailed in Note 15. Government grants received in relation to the drilling of exploration wells are recognised as a reduction in the carrying value of the exploration permit as expenditure is incurred. Consolidated 2023 $million 2022 $million 444.7 119.5 (5.2) – (0.1) (3.8) – 7.1 562.2 334.8 100.1 3.1 (2.3) 0.2 (0.3) (0.1) 9.2 444.7 Exploration and evaluation assets at beginning of financial year Additions Increase/(decrease) in restoration Acquisition of assets and joint operation interests (Note 26) Exploration and evaluation expenditure expensed Disposal of joint operation interests Foreign exchange movement Capitalised depreciation of lease assets Total exploration and evaluation assets 94 Beach Energy Limited Annual Report 2023 11. Intangible assets Goodwill Goodwill represents the excess of the cost of an acquisition over the fair value of the Group’s share of the net identifiable assets of the acquired business combination accounted at the date of acquisition. Goodwill on acquisitions is included in intangible assets. Goodwill is not amortised, but instead tested for impairment annually or more frequently if events or changes in circumstances indicate that it might be impaired, and is carried at cost less accumulated impairment losses. Gains or losses on the disposal of an entity include the carrying amount of goodwill relating to the entity sold. Goodwill is allocated to CGUs for the purpose of impairment testing. An impairment loss is recognised for the amount by which the asset’s carrying amount exceeds its recoverable amount. The recoverable amount of an asset or CGU is the greater of its value-in-use and its fair value less cost of disposal. In assessing value-in-use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. Goodwill acquired in a business combination is allocated to groups of CGUs that are expected to benefit from the synergies of the combination. Impairment losses are recognised in profit or loss unless the asset has previously been revalued, in which case the impairment is recognised as a reversal to the extent of that previous revaluation with any excess recognised in profit or loss. Refer to Note 9 for further information regarding critical accounting estimates and judgements used for impairment testing. Software Software is stated at historical cost less accumulated amortisation. Where costs incurred to configure or customise Software as a Service (SaaS) arrangement result in the creation of a resource which is identifiable, and where the company has the power to obtain the future economic benefits flowing from the underlying resource and to restrict the access of others to those benefits, such costs are recognised as a separate intangible software asset. All software costs are amortised over the useful life of the software on a straight-line basis. The amortisation is reviewed at least at the end of each reporting period and any changes are treated as changes in accounting estimates. Amortisation methods and useful lives The group amortises software assets with a limited useful life using the straight-line method over 5 years. Goodwill Goodwill at cost Less accumulated amortisation Total goodwill Software Software at cost Less accumulated amortisation Total software Reconciliation of movement in software: Balance at beginning of financial year Additions Amortisation expense Total software Total intangibles Consolidated 2023 $million 2022 $million 57.1 – 57.1 52.0 (31.5) 20.5 20.0 6.4 (5.9) 20.5 77.6 57.1 – 57.1 45.6 (25.6) 20.0 20.0 5.5 (5.5) 20.0 77.1 95 Notes to the Financial Statements Notes to and forming part of the Financial Statements for the financial year ended 30 June 2023 12. Interests in joint operations Exploration and production activities are conducted through joint arrangements governed by joint operating agreements, production sharing contracts or similar contractual relationships. A joint operation involves the joint control, and often the joint ownership, of one or more assets contributed to, or acquired for the purpose of the joint operation and dedicated to the purposes of the joint operation. The assets are used to obtain benefits for the parties to the joint operation. Each party may take a share of the output from the assets and each bears an agreed share of expenses incurred. Each party has control over its share of future economic benefits through its share of the joint operation. The interests of the Group in joint operations are brought to account by recognising in the financial statements the Group’s share of jointly controlled assets, share of expenses and liabilities incurred, and the income from the sale or use of its share of the production of the joint operation in accordance with the Group’s revenue policy. Accounting for interests in other entities Judgement is required in assessing the level of control obtained in a transaction to acquire an interest in another entity; depending upon the facts and circumstances in each case, Beach may obtain control, joint control or significant influence over the entity or arrangement. Judgement is applied when determining the relevant activities of a project and if joint control is held over them. Relevant activities include, but are not limited to, work program and budget approval, investment decision approval, voting rights in joint operating committees, amendments to permits and changes to joint arrangement participant holdings. Transactions which give Beach control of a business are business combinations. If Beach obtains joint control of an arrangement, judgement is also required to assess whether the arrangement is a joint operation or a joint venture. If Beach has neither control nor joint control, it may be positioned to exercise significant influence over the entity, which is then accounted for as an associate. The Group has a direct interest in a number of unincorporated joint operations with those significant joint operation interests shown below. Joint Operation Oil and Gas interests Australia Cooper Basin (South Australia) Ex PEL 92 (PRLs 85–104) Ex PEL 513 (PRLs 191–206) Ex PEL 632 (PRLs 131–134) SA Fixed Factor Area SA Unit Cooper Basin (Queensland) Naccowlah Block ATP 299 (Tintaburra) Total 66 Block SWQ Unit Otway Basin (Victoria/Tasmania) Otway Gas Project Bass Basin (Tasmania) BassGas Project Trefoil Perth Basin (Western Australia) Beharra Springs Waitsia Gas Project International Taranaki Basin (New Zealand) Kupe Gas Project Principal activities Oil production Gas production and exploration Gas production and exploration Oil and gas production Oil production Oil production Oil production Oil production Gas production Gas production Gas production Gas development Gas production Gas production % interest 2023 2022 75.0 40.0 40.0 33.4 33.4 38.5 40.0 30.0 39.9 75.0 40.0 40.0 33.4 33.4 38.5 40.0 30.0 39.9 60.0 60.0 88.8 90.3 50.0 50.0 88.8 90.3 50.0 50.0 Gas production 50.0 50.0 Details of commitments for expenditure and contingent liabilities incorporating the Group's interests in joint operations are shown in Notes 15 and 26 respectively. 96 Beach Energy Limited Annual Report 2023 13. Provisions A provision for rehabilitation and restoration is provided by the Group where there is a present obligation as a result of exploration, development, production, transportation or storage activities having been undertaken, and it is probable that an outflow of economic benefits will be required to settle the obligation. The estimated future obligations include the costs of removing facilities, abandoning wells and restoring the affected areas once petroleum reserves are exhausted. Restoration liabilities are discounted to present value and capitalised as a component part of petroleum assets and exploration and evaluation assets. The capitalised costs are amortised over the life of the petroleum assets. Any changes in the estimate are reflected in the present value of the restoration provision at the reporting date, with a corresponding change in the cost of the associated asset. In the event the restoration provision is reduced, the cost of the related petroleum or exploration asset is reduced by an amount not exceeding its carrying value. If the decrease in restoration provision exceeds the carrying amount of the asset, the excess is recognised immediately in the statement of profit or loss as other income. The unwinding of discounting on the provision is recognised as a finance cost through the statement of profit or loss as the discounting of the liability unwinds at the end of each reporting period. Estimate of restoration costs The Group holds provisions for the future removal costs of offshore and onshore oil and gas platforms, production facilities and pipelines at different stages of the development, construction and end of their economic lives. Most of these decommissioning events are many years in the future and the precise requirements that will have to be met when the removal event occurs are uncertain. Decommissioning technologies and costs are constantly changing, as are political, environmental, safety and public expectations. The timing and amounts of future cash flows are subject to significant uncertainty and estimation is required in determining the amounts of provisions to be recognised. The Group’s restoration obligations are based on compliance with the requirements of relevant regulations which vary for different jurisdictions and are often non-prescriptive. Australian legislation requires removal of structures, equipment and property, or alternative arrangements to removal which are satisfactory to the regulator. The Group maintains technical expertise to ensure that industry learnings, scientific research and local and international guidelines are reviewed in assessing its restoration obligations. The provision for restoration requires judgement regarding removal date, environmental legislation and regulations, the extent of restoration activities required, the engineering methodology for estimating cost, removal technologies in determining the removal cost, and inflation and discount rates to determine the present value of these cash flows. It represents the Group’s best estimate based on current industry practice, current legislation and regulations, technology, price levels and expected plans for end of life remediation. Within Beach’s provision the following costs have been provided: – For offshore assets provision has been made for installation of permanent well barriers, sever casings and conductors, recovery of subsea flowlines, umbilicals and manifolds, platform preparation, jacket and topside removal, cutting of piles, removal and disposal of recovered components. It is currently the Group’s intention to leave subsea pipelines in-situ. – For onshore assets provision has been made for demolition and removal of facilities, removal of aboveground pipelines and services, flush and clean and leave in-situ below ground pipelines, removal of contaminated soil, site contouring and revegetation. – For non-operated joint venture assets, the provision recorded represents the Group’s share of the relevant Joint Venture operator estimate as responsibility for the restoration will reside with the operator who has the best knowledge and understanding of the assets. The Group regularly assesses the operator estimates with the assistance of Group appointed experts. Elements composed of steel, or steel and concrete, with hydrocarbons removed such as sub-sea pipelines and other infrastructure have previously been accepted in other international offshore jurisdictions (i.e. North Sea) to be decommissioned in-situ where it has been demonstrated there is an acceptable impact to the environment and to current and future marine users (i.e. fishing, shipping and other activities). The basis of the restoration provision for assets with approved decommissioning plans or general directions issued by the regulator can differ from the assumptions disclosed above. Whilst the provisions reflect the Group’s best estimate based on current knowledge and information, further studies and detailed analysis of the restoration activities for individual assets will be performed near the end of their operational life and/or when detailed decommissioning plans are required to be submitted to the relevant regulatory authorities. Actual costs and cash outflows can materially differ from the current estimate as a result of changes in laws & regulations and their application, prices, discovery and analysis of site conditions, public expectations, further studies, timing of restoration and changes in removal technology. These uncertainties may result in actual costs and cash outflows differing from amounts included in the provision recognised as at 30 June 2023. The timing and amount of future costs relating to decommissioning and environmental liabilities are reviewed annually, together with the inflation and discount rates. The discount rates used to determine the Statement of Financial Position obligations at 30 June 2023 were within the range 3.9% to 4.8% (2022 within the range 2.4% to 4.0%), and were based on applicable government bonds with a tenure aligned to the tenure of the liability. Changes in assumptions in relation to the Group's restoration provision could result in a material change in their carrying amounts within the next financial year. A 0.5% change in the nominal discount rate or inflation rate could have an impact of approximately -$63/+$70 million respectively on the value of the Group’s restoration provision. If the cost estimates were increased by 10% then the provision would be $34 million higher. 97 Notes to the Financial Statements Notes to and forming part of the Financial Statements for the financial year ended 30 June 2023 13. Provisions (continued) Estimated costs in the provision currently assume that all sub-sea pipelines will be left in-situ noting that, whilst the removal of offshore pipelines is the default requirement under current legislation, the existing guidelines provide options other than complete removal if the titleholder can demonstrate that the alternative approach delivers equal or better environmental, safety and well integrity outcomes. The Group currently has plans that we believe would deliver these equal or better outcomes and have prepared the provision using our best estimate of these plans. In addition, cost savings have also been embedded in the cost estimates assuming that restoration activities can be undertaken in an efficient manner, such as part of a campaign. Should the future outcome of negotiations with regulators change these plans or impact our ability to realise the campaign cost savings, these decommissioning activities may need to be expanded or brought forward which may result in additional costs of up to $270 million which are not included in our best estimate and the associated provision recorded at 30 June 2023. Estimate of employee entitlements Annual and long service leave is measured at the present value of benefits accumulated up to the end of the reporting period. The liability is discounted using an appropriate discount rate. Management requires judgement to determine key assumptions used in the calculation including future increases in salaries and wages, future on-cost rates and future settlement dates of employees’ departures. Consolidated 2023 $million 2022 $million 22.9 66.6 1.7 91.2 1.8 969.8 971.6 22.1 13.6 (11.0) 24.7 918.0 120.3 (33.8) 33.9 (2.0) 1,036.4 4.5 – (2.8) 1.7 21.2 63.7 4.5 89.4 0.9 854.3 855.2 20.3 10.3 (8.5) 22.1 962.1 (49.4) (14.4) 17.1 2.6 918.0 – 5.0 (0.5) 4.5 Current Employee entitlements Restoration Other Provisions Total Non-Current Employee entitlements Restoration Total Movement in the Group provisions are set out below Reconciliation of movement in employee entitlements: Balance at beginning of financial year Provision made or reversed during the year Provision paid/used during the year Total Reconciliation of movement in restoration: Balance at beginning of financial year Provision made or reversed during the year Provision paid/used during the year Unwind of discount Foreign exchange movement Total Reconciliation of movement in other provisions: Balance at beginning of financial year Provision made or reversed during the year Provision paid/used during the year Total 98 Beach Energy Limited Annual Report 2023 14. Leases Recognition and measurement as a lessee Leases are recognised as a lease asset and a corresponding liability at the date at which the leased asset is available for use by the Group. A lease is a contract (i.e., an agreement between two or more parties that creates enforceable rights and obligations), or part of a contract, that conveys the right to use an asset for a period of time in exchange for consideration. To be a lease, a contract must convey the right to control the use of an identified asset. Contracts may contain both lease and non-lease components. The Group allocates the consideration in the contract to the lease and non-lease components based on their relative stand-alone prices. The Group has lease contracts for various items of plant, machinery, vehicles, buildings and other equipment used in its operations. The Group has several lease contracts that include extension and termination options. These options are negotiated by management to provide flexibility in managing the leased-asset portfolio and align with the Group’s business needs. Management exercises significant judgement in determining whether these extension and termination options are reasonably certain to be exercised Lease assets are measured at cost, less any accumulated depreciation, and adjusted for any remeasurement of lease liabilities and for impairment losses, assessed in accordance with the Group’s impairment policies. The cost of lease assets includes the amount of lease liabilities recognised, initial direct costs incurred, and lease payments made at or before the commencement date less any lease incentives received. The recognised lease assets are depreciated on a straight-line basis over the shorter of its estimated useful life and the lease term. Contracts may contain both lease and non-lease components. The Group allocates the consideration in the contract to the lease and non-lease components based on their relative stand-alone prices. Judgement is required to determine the Group's rights and obligations for lease contracts within joint operations, to assess whether lease liabilities are recognised gross (100%) or in proportion to the Group’s participating interest in the joint operation. This includes an evaluation of whether the lease arrangement contains a sublease with the joint operation. Instances where the payments regarding a lease contract are part of a joint operations and the Group is the responsible party for payment, the Group recognises the full lease liability, and recognises other income for the portion of payment that is recovered through other parties within the joint venture arrangement. Instances where a sublease is entered into, the Group recognises the full lease liability, and recognises a sublease receivable for the portion of payment that is recovered through other parties within the sublease arrangement. At the commencement date of the lease, the Group recognises lease liabilities measured at the present value of lease payments to be made over the lease term. In calculating the present value of lease payments, the lease payments are discounted using the interest rate implicit in the lease. If that rate cannot be readily determined, which is generally the case for leases in the Group, the Group’s incremental borrowing rate is used, being the rate that the Group would have to pay to borrow the funds necessary to obtain an asset of similar value to the lease asset in a similar economic environment with similar terms, security and conditions. After the commencement date, the amount of lease liabilities is increased by the interest cost and reduced for the lease payments made. In addition, the carrying amount of lease liabilities is remeasured if there is a modification, a change in the lease term, a change in the in-substance fixed lease payments or a change in the assessment to purchase the underlying asset. Lease liabilities include the net present value of the following lease payments: – Fixed payments (including in-substance fixed payments), less any lease incentives receivable; – Variable lease payment that are based on an index or a rate, initially measured using the index or rate as at the commencement date; – Amounts expected to be payable by the Group under residual value guarantees; – The exercise price of a purchase option if the Group is reasonably certain to exercise that option; – Lease payments to be made under reasonably certain extension options; and – Payments of penalties for terminating the lease, if the lease term reflects the Group exercising that option. The Group is exposed to potential future increases in variable lease payments based on an index or rate, which are not included in the lease liability until they take effect. When adjustments to lease payments based on an index or rate take effect, the lease liability is reassessed and adjusted against the lease asset. Lease payments are allocated between principal and finance cost. The finance cost is charged to profit or loss over the lease period to produce a constant periodic rate of interest on the remaining balance of the liability for each period. Instances where the underlying costs regarding a lease contract would previously have been capitalised, the depreciation on the lease asset is capitalised. Payments associated with short-term leases and all leases of assets considered to be of low value are recognised on a straight-line basis as an expense in profit or loss. Short-term leases are leases with a lease term of 12 months or less. 99 Notes to the Financial Statements Notes to and forming part of the Financial Statements for the financial year ended 30 June 2023 14. Leases (continued) Set out below are the carrying amounts of lease assets recognised and the movements during the period: Lease Assets at the beginning of the financial year Additions Lease remeasurement Depreciation expense (1) Total Lease Assets Consolidated 2023 $million 2022 $million 31.7 9.6 2.8 (20.5) 23.6 72.2 24.1 0.2 (64.8) 31.7 (1) Instances where the underlying costs regarding a lease contract can be capitalised, the depreciation on the lease asset is capitalised to exploration and petroleum assets. The Group capitalisation of depreciation is $8.9 million (FY22: $53.6 million). Set out below are the carrying amounts of lease liabilities and the movements during the period: Lease Liabilities at the beginning of the financial year Additions Repayments (2) (3) Lease remeasurement Accretion of interest Foreign exchange movements Total Lease Liabilities Current Non-current Consolidated 2023 $million 2022 $million 33.0 9.6 (22.4) 2.8 1.2 1.0 25.2 11.0 14.2 103.0 24.1 (101.5) 5.6 1.5 0.3 33.0 14.7 18.3 (2) Instances where the payments regarding a lease contract are part of a joint arrangement and the Group is the responsible party for payment, the Group recognises the full lease liability, and recognises other income for the portion of payment that is recovered through other parties within the joint venture arrangement. The Group recognised $3.8 million (FY22: $3.3 million) of other income relating to joint venture recoveries. (3) Instances where the payments regarding a lease contract are part of sublease arrangement and the Group is the responsible party for payment, the Group recognises the full lease liability, and recognises a sublease receivable for the portion of payment that is recovered through other parties within the sublease arrangement. No sublease arrangements have been recognised in the year ended 30 June 2023 (FY22: $25.6 million of sublease repayments received from other parties). Payments of $2.4 million (FY22: $7.7 million) for short-term leases (lease term of 12 months or less) and payments of $0.1 million (FY22: $0.1 million) for leases of low value assets were also accounted for in the year ended 30 June 2023. Other income associated with lease arrangements Where it has been determined that the Group directs the use of the leased asset, and is the only party with legal obligation to pay the lessor, the Group recognises other income for any amount of the lease payments that are recoverable from other parties, representing “other income related to joint venture lease recoveries” in other income. 100 Beach Energy Limited Annual Report 2023 15. Commitments for expenditure Capital Commitments The Group has contracted the following amounts for capital expenditure at the end of the reporting period for which no amounts have been provided for in the financial statements. Due within 1 year Due within 1–5 years Due later than 5 years Consolidated 2023 $million 2022 $million 169.4 – – 169.4 154.0 – – 154.0 Minimum Exploration Commitments The Group is required to meet minimum expenditure requirements of various government regulatory bodies and joint arrangements. These obligations may be subject to renegotiation, may be farmed out or may be relinquished and have not been provided for in the financial statements. Due within 1 year Due within 1–5 years Due later than 5 years Consolidated 2023 $million 2022 $million 5.2 40.9 1.3 47.4 35.4 45.0 2.1 82.5 The Group's share of the above commitments that relate to its interest in joint arrangements are $163.2 million (FY22 $152.6 million) for capital commitments and $17.9 million (FY22 $23.3 million) for minimum exploration commitments. Default on permit commitments by other joint arrangement participants could increase the Group’s expenditure commitments over the forthcoming 5 year period and/or result in relinquishment of tenements. Any increase in the Group’s commitments that arises from a default by a joint arrangement party may be accompanied by a proportionate increase in the Group’s equity in the tenement concerned. Other commercial arrangements Commercial arrangements in place in relation to the transportation, processing and sale of LNG from Waitsia have the potential to give rise to unavoidable costs of up to $65 million for the financial year to 30 June 2024 for unutilised capacity in the event of a delay to timing of first gas from the Waitsia Gas plant. Beach is maturing a number of options to partially mitigate the unutilised capacity under these arrangements. 101 Notes to the Financial Statements Notes to and forming part of the Financial Statements for the financial year ended 30 June 2023 FINANCIAL AND RISK MANAGEMENT This section provides details on the Group’s debt and related financing costs, interest income, cash flows and the fair values of items in the Group’s statement of financial position. It also provides details of the Group’s market, credit and liquidity risks and how they are managed. 16. Finances and borrowings Borrowings are recognised initially at fair value, net of directly attributable transaction costs incurred. Subsequent to initial recognition, borrowings are stated at amortised cost with any difference between cost and redemption being recognised in the profit or loss over the period of the borrowings, on an effective interest basis. Transaction costs are amortised on a straight line basis over the term of the facility. The unwinding of present value discounting on debt and provisions is also recognised as a finance cost. Borrowing costs relating to major oil and gas assets under development are capitalised as a component of the cost of development. Where funds are borrowed specifically for qualifying projects, the actual borrowing costs incurred are capitalised. Where the projects are funded through general borrowings, the borrowing costs are capitalised based on the weighted average cost of borrowing. Borrowing costs incurred after commencement of commercial operations are expensed to the statement of profit or loss and other comprehensive income. Borrowings are classified as current liabilities unless the Group has an unconditional right to defer settlement of the liability for at least 12 months after the end of the reporting period. Interest income is recognised in the profit or loss as it accrues using the effective interest method and if not received at balance date, is reflected in the statement of financial position as a receivable. Net finance expenses/(income) Finance costs Interest expense Discount unwinding on net present value assets and liabilities Finance costs associated with lease liabilities Less borrowing costs capitalised Total finance expenses Interest income Net finance expenses Non-current Borrowings Bank debt Less debt issuance costs Total non-current borrowings Consolidated 2023 $million 2022 $million 3.2 9.8 30.4 1.2 (13.2) 31.4 (4.4) 27.0 385.0 (1.7) 383.3 4.3 2.2 13.1 1.6 (7.5) 13.7 (0.2) 13.5 90.0 (2.7) 87.3 Beach currently has a $675 million Senior Secured Debt Facility comprised of a three year $250 million syndicated revolving loan facility maturing September 2024 (Facility A), a five year $350 million syndicated revolving loan facility maturing September 2026 (Facility B), and three year $75 million bilateral Contingent Instrument facilities (CI Facilities) with a maturity date of September 2024. As at 30 June 2023 $250 million of Facility A and $135 million of Facility B was drawn, with $50 million of the CI Facilities issued. Bank debt bears interest at the relevant reference rate plus a margin, with the effective interest rate in FY23 of 4.46% (FY22 1.42%). 102 Beach Energy Limited Annual Report 2023 17. Cash flow reconciliation For the purpose of the statement of cash flows, cash and cash equivalents includes cash on hand, cash at bank, term deposits with banks, and highly liquid investments in money market instruments, net of outstanding bank overdrafts subject to them being an insignificant risk of change in value and a short term maturity. (a) Reconciliation of cash and cash equivalents Cash at bank Cash and cash equivalents (b) Reconciliation of net profit to net cash provided by operating activities Net profit after tax Less items classified as investing/financing activities: – Loss/(gain) on disposal of non-current assets – Loss/(gain) on sale of joint operation interests Add/(less) non-cash items: – Share based payments – Depreciation and amortisation – Exploration expense – Restoration expense – Foreign exchange loss – Discount unwinding on provision for restoration – Discount unwinding on acquired contract assets and liabilities – Provision for stock obsolescence movement – Gain on reversal of acquired liabilities – Capitalised borrowing costs – Amortisation of borrowing costs Net cash provided by operating activities before changes in assets and liabilities Changes in assets and liabilities net of acquisitions/disposal of subsidiaries: – Decrease/(increase) in trade and other receivables – Decrease/(increase) in inventories – Decrease/(increase) in contract assets – Decrease/(increase) in other current assets – Decrease/(increase) in other non-current assets – Decrease/(increase) in current tax assets – – – – – – Net cash provided by operating activities Increase/(decrease) in provisions Increase/(decrease) in current tax liability Increase/(decrease) in deferred tax liability Increase/(decrease) in trade and other payables Increase/(decrease) in debt establishment fees Increase/(decrease) in contract liabilities (c) Reconciliation of liabilities arising from financing activities to financing cash flows Opening Balance Financing cash flows (1) Non-cash changes Operating cash flows (2) Closing Balance Consolidated 2023 $million 2022 $million 218.9 218.9 254.5 254.5 400.8 500.8 0.5 (1.0) 400.3 (0.1) (0.7) 500.0 2.3 412.2 0.1 – 1.3 33.9 (3.5) 0.4 (16.8) (13.2) 1.0 818.0 (15.6) (59.8) 11.4 19.8 1.8 (24.2) 118.4 (36.2) 93.6 5.7 – (4.3) 928.6 120.4 273.7 15.5 (1.1) 408.5 2.2 376.2 (0.2) (29.5) (0.8) 17.1 (4.0) 4.0 – (7.5) 1.7 918.2 115.2 (5.3) 11.4 0.8 (13.8) – (9.6) 44.4 62.1 114.9 (3.4) (11.7) 1,223.2 277.1 (153.9) 2.2 (5.0) 120.4 (1) Financing cash flows consist of proceeds from borrowings $370 million (FY22: $145 million), repayments of borrowings $75 million (FY22: $230 million) and lease principal repayments $21.3 million (FY22: $68.9 million) in the statement of cash flows. (2) Operating cash flows consist of the debt establishment fees $nil (FY22: $3.4 million) and lease interest repayments $1.1 million (FY22: $1.6 million). 103 Notes to the Financial Statements Notes to and forming part of the Financial Statements for the financial year ended 30 June 2023 18. Financial risk management The Group is exposed to foreign currency risk, commodity price risk, interest rate risk, credit risk and liquidity risk through the ordinary course of business. Management identifies and evaluates all financial risks and reports to the Board on a regular basis, along with detailed analysis of any hedging in place and monitoring against financial risk management policy limits. The Board actively reviews all financial risks and any hedging on a regular basis, and keeps fully informed of the current status of financial markets through updates provided from Management, independent consultants and banking analysts. Derivative financial instruments may be used to hedge exposure to fluctuations in foreign exchange rate, commodity price and interest rates. Hedging of specific risk exposures in accordance with the Board- approved financial risk management policy, aims to minimise potential adverse effects of these risk exposures. The Group does not trade in derivative financial instruments for speculative purposes. The Group classifies its financial instruments in the following categories: financial assets at amortised cost, financial assets at fair value through profit or loss (FVTPL), financial assets at fair value through other comprehensive income (FVOCI), financial liabilities at amortised cost and derivative instruments. The classification depends on the purpose for which the financial instruments were acquired, which is determined at initial recognition based upon the business model of the Group and the characteristics of the contractual cash flows of the instrument. With the exception of trade receivables, the Group initially measures a financial asset at its fair value plus, in the case of a financial asset not at fair value through profit or loss, transaction costs. Trade receivables are measured at the transaction price determined under AASB 15. Financial assets at amortised cost: A financial asset is classified in this category if the asset is held with the objective of collecting contractual cash flows and the contractual terms give rise on specified dates to cash flows that are solely payments of principal and interest. These assets are subsequently measured using the effective interest (EIR) method and are subject to impairment. Gains and losses are recognised in profit or loss when the asset is derecognised, modified or impaired. Financial assets at fair value through other comprehensive income: A financial asset is classified in this category if it relates to debt securities where the contractual cash flows are solely principal and interest and the objective of the Group’s business model is achieved both by collecting contractual cash flows and selling financial assets. Upon disposal, any balance within the OCI reserve for these debt investments is reclassified to the statement of profit or loss. Financial assets at fair value through profit or loss: A financial asset is classified in this category if it is held for trading, designated upon initial recognition at fair value through profit or loss, or mandatorily required to be measured at fair value. Financial assets are classified as held for trading if they are acquired for the purpose of selling or repurchasing in the near term. Derivatives are also classified as held for trading unless they are designated as effective hedging instruments. Financial assets with cash flows that are not solely payments of principal and interest are classified and measured at fair value through profit or loss, irrespective of the business model. A financial asset is classified in this category if acquired principally for the purpose of selling in the near term. Realised and unrealised gains and losses arising from changes in the fair value of these assets are included in profit or loss in the period in which they arise. Financial liabilities: On initial recognition, the Group measures a financial liability at its fair value minus, in the case of a financial liability not at fair value through profit or loss, transaction costs that are directly attributable to the issue of the financial liability. After initial recognition, these financial liabilities are stated at amortised cost. Policies for the recognition and subsequent measurement of derivative liabilities are as outlined below. Derivative instruments: Derivative financial instruments may be entered into by the Group for the purpose of managing its exposures to market risks arising in the normal course of business. Any such instruments would be assessed for hedge accounting. The principal derivatives that may be used are commodity price swap and collar structures, forward foreign exchange and option contracts, and interest rate swaps. The use of derivative financial instruments is subject to a set of policies, procedures and limits approved by the Board of Directors. The Group does not trade in derivative financial instruments for speculative purposes. (a) Fair values Certain assets and liabilities of the Group are recognised in the statement of financial position at their fair value in accordance with accounting standard AASB 13 Fair Value Measurement. The methods used in estimating fair value are made according to how the available information to value the asset or liability fits with the following fair value hierarchy: – Level 1 – the fair value is calculated using quoted prices in active markets for identical assets or liabilities; – Level 2 – the fair value is estimated using inputs other than quoted prices included in Level 1 that are observable for substantially the full term of the asset or liability; and – Level 3 – the fair value is estimated using inputs for the asset or liability that are not based on observable market data. 104 Beach Energy Limited Annual Report 2023 a) Fair values (continued) The carrying amounts and fair values of the Group’s financial assets and financial liabilities are set out below: Financial assets Cash and cash equivalents(1) Receivables(2) Financial liabilities Payables(2) Lease liabilities(2) Interest bearing liabilities(2) (1) Fair value based on level 1 inputs. (2) Fair value based on level 2 inputs. Financial assets/ financial liabilities at carrying value Financial assets/ financial liabilities at fair value Note 2023 $million 2022 $million 2023 $million 2022 $million 218.9 238.1 457.0 332.6 25.2 385.0 742.8 254.5 222.5 477.0 338.3 33.0 90.0 461.3 218.9 238.1 457.0 332.6 25.2 385.0 742.8 254.5 222.5 477.0 338.3 33.0 90.0 461.3 14 16 The methods and valuation techniques used for the purpose of measuring fair value are unchanged compared to the previous reporting period. The following summarises the significant methods and assumptions used in estimating the fair values of financial instruments: The Group did not measure any financial assets or financial liabilities at fair value on a non-recurring basis as at 30 June 2023 and there have been no transfers between the levels of the fair value hierarchy during the year ended 30 June 2023. (b) Market Risk The Group is exposed to commodity price fluctuations through the sale of petroleum products and other oil-linked contracts. Derivatives may be used by the Group to manage its forward commodity price risk exposure. Changes in fair value of these derivatives are initially recognised in the profit or loss, with the effective portion reallocated to other comprehensive income if the transaction is designated as a hedge and qualifies for hedge accounting under AASB 9. Foreign exchange risk arises from commercial transactions, expenditure and valuation of asset and liabilities that are not denominated in the entities functional currency, principally US dollars and New Zealand dollars. To satisfy payment obligations in jurisdictions where the Australian dollar is not accepted, Beach converts funds as payments become due. Funds received in foreign currencies that are surplus to forecast needs are required to be converted to Australian dollars at the prevailing exchange rate. There were no commodity hedges outstanding at 30 June 2022 or 30 June 2023. The Group’s interest rate risk arises from interest bearing cash held on deposit and its bank loan facility which are subject to variable interest rates. The interest rate profile of the Group’s interest-bearing financial instruments is as follows: Variable rate instruments: Cash and cash equivalents Interest bearing liabilities Consolidated 2023 $million 2022 $million 218.9 (385.0) (166.1) 254.5 (90.0) 164.5 Sensitivity analysis for all market risks The following table demonstrates the estimated sensitivity to changes in the relevant market parameter, with all variables held constant, on post tax profit and equity, which are the same as the profit impact flows through to equity. These sensitivities should not be used to forecast the future effect of a movement in these market parameters on future cash flows which may be different where hedging is in place. 105 Notes to the Financial Statements Notes to and forming part of the Financial Statements for the financial year ended 30 June 2023 18. Financial risk management (continued) Impact on post-tax profit and equity US$ oil price – increase of $10/bbl US$ oil price – decrease of $10/bbl A$/$US – 10% appreciation of Australian/US dollar exchange rate A$/$US – 10% depreciation of Australian/US dollar exchange rate Interest rates – increase of 1% p.a. Interest rates – decrease of 1% p.a. Consolidated 2023 $million 2022 $million 53.2 (53.2) (42.8) 52.3 (0.1) 0.1 59.4 (59.4) (54.1) 66.1 (0.7) 0.1 (c) Credit risk Credit risk arises from cash and cash equivalents, derivative financial instruments and deposits with banks and financial institutions, as well as credit exposures to customers, including outstanding receivables and committed transactions, and represents the potential financial loss if counterparties fail to perform as contracted. Management monitors credit risk on an ongoing basis. Gas sales contracts are spread across major Australian and New Zealand energy retailers and industrial users with liquid hydrocarbon products sales being made to major multi-national energy companies based on international market pricing. The Group applied the simplified approach to providing for expected credit losses prescribed by AASB 9, which permits the use of the lifetime expected loss provision for all trade receivables and contract assets. Under this method, determination of the loss allowance provision and expected loss rate incorporates past experience and forward-looking information, including the outlook for market demand and forward-looking interest rates. As the expected loss rate at 30 June 2023 is 0.1% (FY22 0.1%), a loss allowance has been recorded at 30 June 2023 of $0.2 million (FY22 $0.2 million). Ageing of Receivables : Receivables not yet due Receivables past due Considered impaired Total Receivables Consolidated 2023 $million 2022 $million 238.1 0.2 (0.2) 238.1 222.5 0.2 (0.2) 222.5 The Group manages its credit risk on financial assets by predominantly dealing with counterparties with an investment grade credit rating. Customers who wish to trade on unsecured credit terms are subject to credit verification procedures. Cash is placed on deposit amongst a number of financial institutions to minimise the risk of counterparty default. (d) Liquidity Risk The Group operates under a prudent liquidity risk management strategy, ensuring sufficient cash, other liquid assets and available committed credit facilities to meet business requirements. Beach maintains flexibility in funding to meet ongoing operational requirements, exploration and development expenditure, and small-to-medium-sized opportunistic projects and investments, by keeping committed credit facilities available. Details of Beach's financing arrangements are outlined in Note 16. The following table summarises the contractual maturity of the Group’s financial liabilities: Less than 1 year 1 to 5 years Greater than 5 years Total Note 2023 $million 2022 $million 2023 $million 2022 $million 2023 $million 2022 $million 2023 $million 2022 $million 14 16 329.9 11.0 – 340.9 334.9 14.7 – 349.6 2.7 14.2 385.0 401.9 3.0 18.3 90.0 111.3 – – – – 0.4 – – 0.4 332.6 25.2 385.0 742.8 338.3 33.0 90.0 461.3 Financial liabilities Payables Lease liabilities Interest bearing liabilities 106 Beach Energy Limited Annual Report 2023 EQUITY AND GROUP STRUCTURE This section provides information which will help users understand the equity and group structure as a whole including information on equity, reserves, dividends, subsidiaries, the parent company, related party transactions and other relevant information. 19. Contributed equity Ordinary shares are classified as equity. Transaction costs of an equity transaction are accounted for as a reduction to the proceeds received, net of any related income tax benefit. Transaction costs are the costs that are incurred directly in connection with the issue of those equity instruments and which would not have been incurred had those instruments not been issued. Issued and fully paid ordinary shares at 30 June 2021 Issued during the FY22 financial year Repayment of employee loans and sale of employee shares Shares purchased on market (Treasury shares), net of tax Utilisation of Treasury shares on vesting of shares and rights under employee and executive incentive plans Issued and fully paid ordinary shares at 30 June 2022 Issued during the FY23 financial year Repayment of employee loans and sale of employee shares Shares purchased on market (Treasury shares), net of tax Utilisation of Treasury shares on vesting of shares and rights under employee and executive incentive plans Issued and fully paid ordinary shares at 30 June 2023 Number of Shares 2,281,333,656 – – – 2,281,333,656 – – – 2,281,333,656 $million 1,859.5 1.0 (0.7) 2.5 1,862.3 0.8 (0.6) 0.8 1,863.3 Treasury shares Treasury shares are held to satisfy the obligations under the employee and executive incentive plans. Shares are accounted for at the weighted average cost for the period. During the year $0.8 million (FY22: $1.0 million) of Treasury shares were purchased on market. Movement in Treasury shares Balance at 30 June 2021 Shares purchased on market during FY22 Utilisation of Treasury shares on vesting of rights under executive incentive plan Balance at 30 June 2022 Shares purchased on market during FY23 Utilisation of Treasury shares on vesting of rights under executive incentive plan and employee share plan Balance at 30 June 2023 Number 2,974,400 709,379 (1,763,535) 1,920,244 575,701 (507,050) 1,988,895 In accordance with Corporations Act 2001 shares issued do not have a par value as there is no limit on the authorised share capital of the Company. All shares issued under the Company’s employee incentive plan are accounted for as a share-based payment (refer Note 4 and 20 for further details). Shares issued under the Company’s dividend reinvestment plan and employee incentive plan represent non-cash investing and financing activities. On a show of hands, every person qualified to vote, whether as a member or proxy or attorney or representative, shall have one vote. Upon a poll, every member shall have one vote for each ordinary share held. Pursuant to the employee share plan trust, the trustee shall not vote any shares held in respect of the employee incentive plan or executive incentive plan, except where it is incidental to providing shares to the participants in the plan. Details of shares and rights issued and outstanding under the Employee Incentive Plan and Executive Incentive Plan are provided in Note 4. 107 Notes to the Financial Statements Notes to and forming part of the Financial Statements for the financial year ended 30 June 2023 19. Contributed equity (continued) Dividend Reinvestment Plan The Board suspended the operation of the Dividend Reinvestment Plan on 21 August 2017 on the basis that this form of capital management is not required at this time. Capital management Management is responsible for managing the capital of the Group, on behalf of the Board, in order to maintain an appropriate debt to equity ratio, provide shareholders with adequate returns and ensure the Group can fund its operations with secure, cost-effective and flexible sources of funding. The Group debt and capital includes ordinary shares, borrowings and financial liabilities supported by financial assets. Management effectively manages the capital of the Group by assessing the financial risks and adjusting the capital structure in response to changes in these risks and in the market. The responses include the management of debt levels, dividends to shareholders and share issues. The Group net gearing ratio is 4.1% (FY22 1.5%). Net gearing has been calculated as interest bearing liabilities less cash and cash equivalents, as a proportion of these items plus shareholder’s equity. 20. Reserves The share based payments reserve is used to recognise the fair value of shares, options and rights issued to employees of the Company. The Foreign currency translation reserve is used to record foreign exchange differences arising from the translation of the financial statements of subsidiaries with functional currencies other than Australian dollars. The Profit distribution reserve represents an amount allocated from retained earnings that is preserved for future dividend payments. Share based payments reserve Foreign currency translation reserve Profit distribution reserve Total reserves 21. Dividends Consolidated 2023 $million 2022 $million 37.7 (7.5) 721.6 751.8 36.1 (10.5) 790.0 815.6 A provision is recognised for dividends when they have been announced, determined or publicly recommended by the directors on or before the reporting date. Final dividend of 1.0 cent (2022 1.0 cent) Interim dividend of 2.0 cent (2022 1.0 cent) Total dividends paid or payable Consolidated 2023 $million 2022 $million 22.8 45.6 68.4 22.8 22.8 45.6 Franking credits available in subsequent financial years based on a tax rate of 30% (2022: 30%) 593.8 549.5 108 Beach Energy Limited Annual Report 2023 22. Subsidiaries Name of Company Place of incorporation Percentage of shares held % 2023 % 2022 Beach Energy Limited (1) Beach Energy (Operations) Limited (1) Beach Energy (Perth Basin) Pty Ltd (1) Beach Energy (Bonaparte) Pty Ltd Beach Energy (Bass Gas) Limited Beach Energy Services Pty Ltd Beach Energy Finance Pty Ltd Beach Energy (Offshore) Pty Ltd Beach Petroleum (NZ) Pty Ltd Beach Oil and Gas Pty Ltd Beach Production Services Pty Ltd Beach Petroleum (Cooper Basin) Pty Ltd Beach (Tanzania) Pty Ltd Beach Petroleum (Tanzania) Limited Beach Energy (Otway) Limited Beach Petroleum (NT) Pty Ltd Territory Oil & Gas Pty Ltd Adelaide Energy Pty Ltd Australian Unconventional Gas Pty Ltd Deka Resources Pty Ltd Well Traced Pty Ltd Australian Petroleum Investments Pty Ltd (1) Delhi Holdings Pty Ltd Delhi Petroleum Pty Ltd (1) Impress Energy Pty Ltd (1) South Australia South Australia New South Wales South Australia Victoria Victoria Tanzania South Australia Australian Capital Territory South Australia UK Victoria Victoria South Australia UK Victoria Northern Territory South Australia South Australia South Australia South Australia Victoria Victoria South Australia Western Australia Victoria Western Australia Liberia Queensland Victoria New South Wales Queensland New South Wales New South Wales Victoria Victoria USA Victoria Queensland New South Wales New Zealand New Zealand New Zealand New Zealand New Zealand Beach Energy Resources NZ (Clipper) Limited New Zealand Beach Energy Resources NZ (Tawhaki) Limited Beach Energy Resources NZ (Tawn) Limited New Zealand Beach Energy Resources NZ (Wherry No.1) Limited New Zealand Beach Energy Resources NZ (Wherry No.2) Limited New Zealand Mazeley Ltd Mawson Petroleum Pty Ltd Drillsearch Energy Pty Ltd (1) Circumpacific Energy (Australia) Pty Ltd Drillsearch Gas Pty Ltd Drillsearch (Field Ops) Pty Ltd Drillsearch (513) Pty Ltd Drillsearch (Central) Pty Ltd Ambassador Oil & Gas Pty Ltd Ambassador (US) Oil & Gas LLC Ambassador Exploration Pty Ltd Acer Energy Pty Ltd Great Artesian Oil & Gas Pty Ltd (1) Beach Energy Resources NZ (Holdings) Limited Beach Energy Resources NZ (Kupe) Limited Beach Energy (Kupe) Limited Impress (Cooper Basin) Pty Ltd (1) Springfield Oil and Gas Pty Ltd (1) Kupe Mining (No.1) Limited All shares held are ordinary shares, other than Mazeley Ltd which is held by a bearer share. (1) Company in Closed Group in FY22 and FY23 (refer Note 23). 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 109 Notes to the Financial Statements Notes to and forming part of the Financial Statements for the financial year ended 30 June 2023 23. Deed of cross guarantee Pursuant to ASIC (wholly-owned companies) Instrument 2016/785, certain wholly-owned subsidiaries can be relieved from the Corporations Act 2001 requirements for preparation, audit and lodgement of their financial reports. As a condition of the Class Order, Beach and each of the subsidiaries that opted for relief during the year (the Closed Group) entered into a Deed of Cross Guarantee (Deed). The effect of the Deed is that Beach has guaranteed to pay any deficiency in the event of winding up of any of the subsidiaries under certain provisions of the Corporations Act 2001. The Subsidiaries have also given a similar guarantee in the event that Beach is wound up. Those companies in the Closed Group for each year are referred to in Note 22. The consolidated statement of profit or loss and other comprehensive income, summary of movements in retained earnings/(accumulated losses) and statement of financial position of the Closed Group are as follows: Consolidated Statement of Profit or Loss and Other Comprehensive Income Revenue Cost of sales Gross profit Other income Other expenses Operating profit before financing costs Interest income Finance expenses Profit before income tax expense Income tax expense Profit after tax for the year Other comprehensive income/(loss) net of tax Total comprehensive income/(loss) after tax Summary of movements in the Closed Group’s retained earnings/(accumulated losses) Retained earnings at beginning of the year Net profit for the year Retained earnings/(accumulated losses) at end of the year Closed Group 2023 $million 2022 $million 1,442.8 (955.4) 487.4 1,504.3 (885.1) 619.2 268.6 1.1 757.1 – (34.3) 722.8 (212.1) 510.7 – 0.8 (37.8) 582.2 – (18.1) 564.1 (174.5) 389.6 – 510.7 389.6 465.9 510.7 976.6 76.3 389.6 465.9 110 Beach Energy Limited Annual Report 2023 Consolidated Statement of Financial Position Current assets Cash and cash equivalents Receivables Inventories Current tax asset Other Total current assets Non-current assets Property, plant and equipment Petroleum assets Exploration and evaluation assets Lease assets Intangible Assets Other financial assets Other Total non-current assets Total assets Current liabilities Payables Provisions Current tax liability Lease liabilities Total current liabilities Non-current liabilities Payables Provisions Lease liabilities Deferred Tax Liability Interest bearing liabilities Total non-current liabilities Total liabilities Net assets Equity Contributed equity Reserves Retained earnings/(accumulated losses) Total equity Closed Group 2023 $million 2022 $million 191.0 234.6 149.2 24.2 13.4 612.4 7.1 4,192.1 455.4 22.2 75.7 291.7 60.5 5,104.7 5,717.1 297.2 80.3 76.8 10.2 464.5 259.0 803.7 13.5 193.5 383.3 1,653.0 2,117.5 3,599.6 1,863.3 759.7 976.6 3,599.6 243.3 229.7 92.1 – 99.4 664.5 7.1 3,470.4 334.9 30.4 75.7 291.7 60.2 4,270.4 4,934.9 306.7 78.0 14.0 14.3 413.0 524.9 671.6 17.3 88.3 87.3 1,389.4 1,802.4 3,132.5 1,862.3 804.3 465.9 3,132.5 111 Notes to the Financial Statements Notes to and forming part of the Financial Statements for the financial year ended 30 June 2023 24. Parent entity financial information Selected financial information of the parent entity, Beach Energy Limited, is set out below: Financial performance Net profit/(loss) after tax Other comprehensive income/(loss), net of tax Total comprehensive income after tax Total current assets Total assets Total current liabilities Total liabilities Issued capital Share based payments reserve Profits distribution reserve Other reserve Retained earnings Total equity Parent 2023 $million 274.9 – 274.9 819.0 2022 $million 44.8 – 44.8 1,161.9 2,497.8 2,753.0 50.1 664.3 1,863.3 37.7 721.6 0.6 (789.7) 1,833.5 947.9 1,128.6 1,862.3 36.1 790.0 0.6 (1,064.6) 1,624.4 Expenditure Commitments The Company’s contracted expenditure at the end of the reporting period for which no amounts have been provided for in the financial statements. Capital expenditure commitments Minimum exploration commitments Parent 2023 $million 2022 $million 6.2 – 14.1 – Contingent liabilities and guarantees Details of contingent liabilities for the Company in respect of service agreements, bank guarantees and parent company guarantees are disclosed in Note 26. Beach Energy Limited and a number of its wholly owned subsidiaries are parties to a Deed of Cross Guarantee as disclosed in Note 23. The effect of the Deed is that Beach Energy Limited has guaranteed to pay any deficiency in the event of winding up of any of the listed subsidiary companies under certain provisions of the Corporations Act 2001. Parent entity financial information has been prepared using the same accounting policies as the consolidated financial statements except for investments in controlled entities which are included in other financial assets and are initially recorded in the financial statements at cost. These investments may have subsequently been written down to their recoverable amount determined by reference to the net recoverable assets of the controlled entities at the end of the reporting period where this is less than cost. 112 Beach Energy Limited Annual Report 2023 25. Related party disclosures Transactions with related parties are on normal commercial terms and conditions no more favourable than those available to other parties unless otherwise stated. Remuneration for Key Management Personnel Short term benefits Share based payments Other long term benefits Termination payments Total Subsidiaries Interests in subsidiaries are set out in Note 22. Consolidated $ $ 5,389,467 1,721,581 110,548 – 7,221,596 6,498,981 1,378,686 16,314 653,712 8,547,593 Transactions with other related parties During the financial year ended 30 June 2023, Beach paid $686,936 (FY22 $624,877) to Coates Hire Operations Pty Ltd, an entity of which Ryan Stokes and Richard Richards are both directors, for the hire of equipment on arm’s length commercial terms. A contribution of $22,000 (FY22 $nil) was made to the Curtin Reservoir Geophysics Consortium at Curtin University for the year ended 30 June 2023, an organisation of which Peter Moore is an Advisory Council Member of the Faculty of Science and Engineering. Director’s fees payable to Glenn Davis for the year ended 30 June 2023 of $305,000 (FY22 $305,000) were paid directly to DMAW Lawyers. OTHER INFORMATION Additional information required to be disclosed under Australian Accounting Standards. 26. Contingent liabilities The directors are of the opinion that the recognition of a provision is not required in respect of the following matters, as 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. Service agreements Service agreements exist with executive officers under which termination benefits may, in appropriate circumstances, become payable. The maximum contingent liability at 30 June 2023 under the service agreements for the executive officers is $1,791,787 (FY22 $1,961,077). Bank guarantees As at 30 June 2023, Beach has been provided with a three year $75 million bilateral Contingent Instrument facilities (CI Facilities), of which $50 million had been utilised by way of bank guarantees or letters of credit as security predominantly for our environmental obligations and work programs (refer Note 16 for further details on the corporate debt facility). Joint Venture Operations In the ordinary course of business, the Group participates in a number of joint ventures which is a common form of business arrangement designed to share risk and other costs. Failure of the Group’s joint venture partners to meet financial and other obligations may have an adverse financial impact on the Group. 113 Notes to the Financial Statements Notes to and forming part of the Financial Statements for the financial year ended 30 June 2023 26. Contingent liabilities (continued) Tax obligations In the ordinary course of business, the Group is subject to audits from government revenue authorities which could result in an amendment to historical tax positions. Parent Company Guarantees Beach has provided parent company guarantees in respect of performance obligations for certain exploration interests. Restoration obligations (refer Note 13) The Group holds provisions for the future removal costs of offshore and onshore oil and gas platforms, production facilities and pipelines at different stages of the development, construction and end of their economic lives. Most of these decommissioning events are many years in the future and the precise requirements that will have to be met when the removal event occurs are uncertain. Decommissioning technologies and costs are constantly changing, as are political, environmental, safety and public expectations. The timing and amounts of future cash flows are subject to significant uncertainty and estimation is required in determining the amounts of provisions to be recognised with the provision representing the Group’s best estimate based on current industry practice, regulations, technology, price levels and expected plans for end of life remediation. Estimated costs in the provision currently assume that all major sub-sea pipelines will be left in-situ noting that, whilst the removal of offshore pipelines is the default requirement under current legislation, the existing guidelines provide options other than complete removal if the titleholder can demonstrate that the alternative approach delivers equal or better environmental, safety and well integrity outcomes. The Group currently has plans that we believe would deliver these equal or better outcomes and have prepared the provision using our best estimate of these plans. In addition, cost savings have also been embedded in the cost estimates assuming that restoration activities can be undertaken in an efficient manner, such as part of a campaign. Should the future outcome of negotiations with regulators change these plans or impact our ability to realise the campaign cost savings, these decommissioning activities may need to be expanded or brought forward which may result in additional cost which are not included in our best estimate and the associated provision recorded at 30 June 2023. The Offshore Petroleum and Greenhouse Gas Storage Amendment (Titles Administration and Other Measures) Act 2021 (Titles Administration Act) was legislated to improve Australia's decommissioning framework for offshore oil and gas projects. The bill amendments are as follows: – oversight of changes in company control (such as through a corporate merger or acquisition); – an expansion of existing powers to ‘call back’ previous titleholders to decommission and remediate the environment (also known as trailing liability); – the inclusion of decision making criteria and expanded information gathering powers to assess suitability of companies operating in the offshore oil and gas regime; and – minor and technical amendments to improve the operation of the OPGGS Act, including enabling for electronic lodgement of applications. Under the current framework a titleholder can only be ‘called back’ when a title has ceased through termination, expiration, revocation, cancellation or has been surrendered. The enhanced framework would empower the regulator and the responsible Commonwealth Minister to ‘call back’ a previous titleholder to remediate the title area, regardless of how its interest in the title ceased. Requiring a former titleholder to decommission and remediate the environment is intended to be an option of last resort where all other regulatory options have been exhausted. This legislation has not materially impacted the financial position or performance of the Group as at 30 June 2023. Shareholder class action One of two competing shareholder class actions filed against Beach in November 2021 has been dismissed. The remaining claim is proceeding in the Victorian Supreme Court. At this stage, it is not possible to determine what financial impact, if any, these claims may have on Beach’s financial position. In respect of the substance of the claims, Beach considers that it has at all times complied with its disclosure obligations, denies any liability and will vigorously defend the proceedings. Legal proceedings and claims The Group may be involved in various other legal proceedings and claims in the ordinary course of business, including contractual, third party, contractor and regulatory claims. While the outcome of these legal proceedings and claims cannot be predicted with certainty, it is the directors’ opinion that as of the date of this report, it is unlikely these claims will have a material adverse impact on the Group. 114 Beach Energy Limited Annual Report 2023 27. Remuneration of auditors Fees to Ernst & Young (Australia) Auditing or reviewing the financial statements of the Group Other assurance services required by legislation Other assurance services not required by legislation Total fees to Ernst & Young (Australia) Fees to other overseas member firms of Ernst & Young (Australia) Auditing the financial statements of controlled entities Other assurance services not required by legislation Total fees to other overseas member firms of Ernst & Young (Australia) Fees to other audit firms Auditing financial statements of controlled entities Total fees to other firms Total auditor’s remuneration 28. Subsequent events Consolidated 2023 $000 830 40 203 1,073 80 33 113 19 19 1,205 2022 $000 800 40 152 992 80 30 110 17 17 1,119 On 9 August 2023, Beach appointed Mr Brett Woods as Managing Director and Chief Executive Officer (MD & CEO) to commence 21 February 2024 or such other date as mutually agreed. Mr Woods has over 25 years of experience in upstream oil and gas including most recently 10 years at Santos where he undertook a number of executive roles including Chief Operating Officer, Vice President Developments and Vice President Eastern Australia business unit. In the intervening period current non-executive director Mr Bruce Clement has been appointed interim Chief Executive Officer and continues as an executive director with Mr Morné Engelbrecht ending his tenure as Chief Executive Officer. Other than the matters described above, there has not arisen in the interval between 30 June 2023 and up to the date of this report, any item, transaction or event of a material and unusual nature likely, in the opinion of the directors, to affect substantially the operations of the Group, the results of those operations or the state of affairs of the Group in subsequent financial years, unless otherwise noted in the financial report. 115 Independent Auditor’s Report 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 Beach Energy Limited Report on the audit of the financial report Opinion We have audited the financial report of Beach Energy Limited (the Company), which comprises the statement of financial position as at 30 June 2023, the statement of profit or loss and comprehensive income, statement of changes in equity and 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 Company is in accordance with the Corporations Act 2001, including: a. Giving a true and fair view of the Company’s financial position as at 30 June 2023 and of its 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 Company 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 116 Beach Energy Limited Annual Report 2023 Page 2 Carrying value of petroleum assets Why significant How our audit addressed the key audit matter At 30 June 2023 the Group had petroleum assets of $4,482.1 million. Australian Accounting Standards require the Group to assess at the end of each reporting period whether there is any indication that an asset may be impaired, or that 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 cash generating unit (CGU). Where a CGU includes goodwill an annual impairment test is required. The Group undertook impairment testing in respect of its petroleum asset CGU’s, which resulted in no impairment charge being recorded for the year. The assessment of indicators of impairment and reversal of impairment is judgemental and includes an assessment of a range of external and internal factors which could impact the recoverable amount of the CGUs. Forecasting cashflows for the purpose of determining the recoverable amount of a CGU involves critical accounting estimates and judgements and is affected by expected future performance and market conditions. The key forecast assumptions including commodity prices, discount rates, foreign exchange rates, and recoverable reserves and resources volumes used in the Group’s impairment assessment are set out in the Financial Report in Note 9. We considered the impairment testing of the Group’s petroleum asset CGUs and the related disclosures in the financial report to be a key audit matter. Assessing indicators of impairment: • Evaluated the assumptions, methodologies and conclusions used by the Group in assessing for indicators of impairment and impairment reversal. • Evaluated whether there had been significant changes to the external or internal factors specific to the Group or individual CGUs, as well as broader industry specific or market-based indicators, and the Group’s market capitalisation. Impairment testing of CGUs: We assessed the composition of the forecast cash flows and the reasonableness of key estimates, inputs and assumptions impacting on management’s calculated recoverable amount for those CGUs. These procedures included: • • • • • Independently developing a reasonable range of forecast oil and gas prices, foreign exchange rates and inflation rates with reference to data points available from market and industry research, market practice, market indices, broker consensus, industry experts, and historical performance, against which we compared the Group’s inputs. Independently developing a range of reasonable discount rates to assess whether the Group’s weight average cost of capital (WACC) applied to its CGU’s was reasonable (which contemplates cost of capital considerations related to decarbonisation of the global economy). Analysing forecast operating and capital cost assumptions against historical performance, latest approved budgets and forecasts, long term assets plans and other information obtained throughout the audit. Comparing the carrying value of producing assets against recent comparable market transactions and the market value of comparable companies, where available. Performing sensitivity analysis, to assess changes in recoverable amounts arising due to changes in key inputs, such as alternative gas prices, or foreign exchange rate forecasts. 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 considered the work of the Group’s internal and external experts and included: • • • • • Assessing the processes and controls associated with estimating reserves and resources. Examining the information provided by the Group’s internal and external experts with respect to the hydrocarbon reserve and resource assumptions used in the cash flow forecasts, including reading their reports. Assessing the qualifications, competence and objectivity of the Group’s internal and external experts involved in the estimation process and assessing their scope of work and methodology applied. Considering whether key economic assumptions used in the estimation of reserves and resources volumes were consistent with those used by the Group in the impairment testing of petroleum assets and goodwill, where applicable. Understanding the reasons for reserve changes or the absence of reserves changes, for consistency with other information that we obtained throughout the audit. A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation 117 Independent Auditor’s Report Page 3 Why significant How our audit addressed the key audit matter • Reconciling future production profiles, including resource conversion, to the latest hydrocarbon reserves and resources estimates, current sanctioned development budgets and historical operations. Impact of Sustainability and Climate-Related Risks In undertaking our impairment procedures, we considered sustainability and climate change-related risks by: • • • Understanding the impact of the Group’s communications and publicly stated climate-related commitments on its impairment indicator and impairment testing processes. Identifying CGUs most impacted by legislated carbon reduction targets, and evaluating whether modelled carbon reduction volumes are in accordance with the legislated carbon reduction targets and publicly stated climate related commitments. Evaluating the Group’s carbon pricing assumptions and sensitivity analysis performed to assess the impact on the recoverable amount of the Group’s CGU required to comply with legislated carbon reduction targets. Disclosures in the financial report • Assessed the adequacy of the disclosures in Note 9 and the basis of preparation set out in the financial report. A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation 118 Beach Energy Limited Annual Report 2023 Page 4 Accounting for restoration provisions 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 $1,036.4 million. The calculation of restoration provisions requires significant judgement and estimation, including: • • • Timing and extent of restoration obligations and activities to comply with applicable environmental legislation and regulation. Cost estimates and restoration methods, informed by the work of specialist engineers and technical advisors. Liability specific discount rates used to determine the present value of the future obligations. The judgements and estimates in respect of restoration provisions are based upon conditions existing at 30 June 2023. This includes key assumptions related to certain items remaining in-situ, where certainty of the outcome will only be known some years in the future towards the end of the respective asset’s field life, and accordingly, at 30 June 2023 there is uncertainty regarding 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. In this context, the disclosures set out in Notes 13 and 26 of the financial report provide important information about the assumptions made in the calculation of the restoration provision and uncertainties at 30 June 2023, in arriving at the Groups 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. Our audit procedures included the following: • Evaluating management’s process for identifying legal and regulatory obligations for restoration and decommissioning and ensuring completeness of locations, infrastructure and facilities. • • • • • • • • • • Testing controls over the Group’s internal methodology for determining and approving gross cost estimates used to calculate the Group’s restoration provisions. Assessing the competence and objectivity of the Group’s internal and external experts engaged to prepare gross restoration cost estimates and evaluating whether the information provided by the Group’s internal and external experts was appropriately reflected in the calculation of the restoration provisions. Comparing current year cost estimates to those of the prior year and considered explanations by management and its experts for observed changes. Assessing the adequacy and completeness of restoration cost estimates based on current legal and regulatory requirements, national and international industry precedent and other corroborative evidence. Evaluating the assumptions associated with the form and extent of abandonment activities, including conformity with regulation and/or industry practice and the nature of the items expected to fully removed, partially removed or abandoned in-situ, as part of restoration activities. Reviewing litigation registers, correspondence with solicitors and regulators to confirm the completeness of liabilities recognised. Comparing the timing of the future cash outflows against the anticipated end-of-field lives, cross-checking that these dates are consistent with the Group’s reserve estimates and impairment calculations, and legislated requirements relating to the period following cessation of production within which decommissioning works must commence. Evaluating the appropriateness of the discount rates, inflation rates and foreign exchange rates used to calculate the present value of each of the provisions. Testing the mathematical accuracy of the restoration provision calculations. Assessing the adequacy of the disclosures in Note 13 and 26 of the financial report. 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 2023 annual report, but does not include the financial report and our auditor’s report thereon. Our opinion on the financial report does not cover the other information and accordingly we do not express any form of assurance conclusion thereon, with the exception of the Remuneration Report and our related assurance opinion. A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation 119 Independent Auditor’s Report Page 5 In connection with our audit of the financial report, our responsibility is to read the other information and, in doing so, consider whether the other information is materially inconsistent with the financial report or our knowledge obtained in the audit or otherwise appears to be materially misstated. If, based on the work we have performed, we conclude that there is a material misstatement of this other information, we are required to report that fact. We have nothing to report in this regard. 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 Company’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 Company or to cease operations, or have no realistic alternative but to do so. Auditor’s responsibilities for the audit of the financial report Our objectives are to obtain reasonable assurance about whether the financial report as a whole is free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with the Australian Auditing Standards will always detect a material misstatement when it exists. Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions of users taken on the basis of this financial report. 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 Company’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 Company’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 A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation 120 Beach Energy Limited Annual Report 2023 Page 6 evidence obtained up to the date of our auditor’s report. However, future events or conditions may cause the Company 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. 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 55 to 70 of the directors’ report for the year ended 30 June 2023. In our opinion, the Remuneration Report of Beach 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 L A Carr Partner Adelaide 14 August 2023 A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation 121 Glossary A$ or $ Australian dollars 2C 3D 1P 2P 3P AASB ACCU AGM AOI ASX ATP BassGas Project bbl Bcf Beach Beharra Springs boe Board bp Best estimate of contingent resources (petroleum or storage)(1) Three dimensional Low estimate of reserves or capacity (proved)(1) Best estimate of reserves or capacity (proved plus probable)(1) High estimate of reserves or capacity (proved plus probable plus possible)(1) Australian Accounting Standards Board Australian Carbon Credit Unit Annual General Meeting Area of interest Australian Securities Exchange Authority To Prospect (Qld) The BassGas Project (Beach 88.75% and operator, Prize Petroleum International 11.25%), produces gas from the offshore Yolla gas field in the Bass Basin in production licence T/L1. Beach also holds a 90.25% operated interest in licenses T/RL2 (pending production licence application), T/RL4 and T/RL5 (Prize Petroleum International 9.75%) Barrels Billion cubic feet Beach Energy Limited Beharra Springs (Beach 50% and operator, MEPAU 50%) produces gas from the onshore Beharra Springs gas field in the Perth Basin in production licences L11 and L22 Barrels of oil equivalent – the volume of hydrocarbons expressed in terms of the volume of oil which would contain an equivalent volume of energy Board of Directors of Beach BP Singapore Pte. Limited, a subsidiary of BP plc Bridgeport Bridgeport (Cooper Basin) Pty Ltd CAGR CCS CEO CGU Compounded annual growth rate Carbon capture and storage Chief Executive Officer Cash generating unit Company Beach and its subsidiaries Cooper Energy Cooper Energy Ltd and its subsidiaries Cooper Basin Includes both Cooper and Eromanga Basins CBJV (Cooper Basin JV) The Santos operated SACB JVs and SWQ JVs and ATP 299 (Tintaburra – Beach 40%, Santos 60% and operator) DBNGP DTA EBITDA EIP EP EPS Ex PEL 91 Ex PEL 92 Dampier to Bunbury Natural Gas Pipeline Deferred tax assets Earnings before interest, tax, depreciation and amortisation Executive Incentive Plan Exploration Permit Earnings per share PRLs 151 to 172 and various production licences (Beach 100% and operator) PRLs 85 to 104 and various production licences (Beach 75% and operator, Cooper Energy 25%) Ex PEL 104/111 PRLs 136 to 150 and various production licences (Beach 100% and operator) Ex PEL 106 Ex PEL 513 Ex PEL 632 FEED FID PRLs 129 and 130 and various production licences (Beach 100% and operator) PRLs 191 to 206 and various production licences PRLs 131 to 134 and various production licences Front-End Engineering Design Final investment decision Free cash flow Operating cash flow less investing cash flow (excluding acquisitions and divestitures) FY23 Genesis Group GSA GJ HBWS Financial year 2023 Genesis Energy Limited and its subsidiaries Beach and its subsidiaries Gas sales agreement Gigajoule Halladale/Black Watch/Speculant fields in the offshore Otway Basin in licenses VIC/L1(v) and VIC/P42(v) H1 FY23 First half year period of FY23 HoA IFRS JV JVP kbbl kboe kbopd km KMP KPI kt Kupe Heads of Agreement International Financial Reporting Standards Joint Venture Joint Venture Partner Thousand barrels of oil Thousand barrels of oil equivalent Thousand barrels of oil per day Kilometre Key management personnel Key performance indicator Thousand tonnes Kupe Gas Project (Beach 50% and operator, Genesis 46%, NZOG 4%) produces gas from the offshore Kupe gas field in the Taranaki Basin in licence PML 38146 (1) A full list of reserves, storage and contingent resources definitions are contained within the Petroleum Resources Management System (SPE-PRMS) and Storage Resources Management System (SPE-SRMS). 122 Beach Energy Limited Annual Report 2023 LNG LPG LTI MEPAU Mitsui MMbbl MMboe MMscf MMscfd Mt Liquefied natural gas Liquefied petroleum gas Long term incentive Mitsui E&P Australia Mitsui &Co., Ltd and its subsidiaries Million barrels of oil Million barrels of oil equivalent Million standard cubic feet of gas Million standard cubic feet of gas per day Million tonnes Net Gearing The ratio of net debt/(cash) to the sum of net debt/(cash) and total book equity NPAT NZ NZOG Net profit after tax New Zealand New Zealand Oil & Gas Limited and its subsidiaries O.G. Energy O.G. Energy Holdings Limited, a member of the Ofer Global group of companies Otway Gas Project. Beach 60% and operator. Consists of offshore gas fields Thylacine and Geographe, the Thylacine Well Head Platform, Otway Gas Plant and associated infrastructure ROC SACB JV Santos SA Senex SGH SPA SPE STI SWQ JV Tcf TFR TJ TRIFR TSR Return on capital South Australian Cooper Basin Joint Ventures, which includes the Fixed Factor Area (Beach 33.4%, Santos 66.6% and operator) and the Patchawarra East Block (Beach 27.68%, Santos 72.32% and operator) Santos Limited and its subsidiaries South Australia reporting segment Senex Energy Limited Seven Group Holdings Limited Sale and Purchase Agreement Society of Petroleum Engineers Short Term Incentive South West Queensland Joint Ventures, incorporating various equity interests (Beach 30–52.5%; Santos operator) Trillion cubic feet Total Fixed Remuneration Terajoule Total recordable injury frequency rate Total shareholder return Udacha Block PRL 26 OMV Group and its subsidiaries US$ United States $ Origin Energy Limited and its subsidiaries Victorian Otway Basin OGP OMV Origin Other Cooper Basin Other Cooper Basin producing permit areas are ex PEL 513/632 (Beach 40%, Santos 60% and operator) and ex PEL 182 (Vanessa) (Beach 100%) Prior corresponding period Petroleum Exploration Licence (SA) Petroleum Exploration Permit (Victoria and NZ) PCP PEL PEP Perth Basin Includes Beach’s Waitsia and Beharra Springs assets WA Waitsia PL PPL PJ Petroleum Lease (QLD) Petroleum Production Licence (SA) Petajoule Pre-Growth Free Cash Flow Operating Cash Flows, less investing cash flows excluding acquisitions, divestments and major growth capital expenditure, less lease liability payments Prize PRL PRMS PRRT Prize Petroleum Licence Petroleum Retention Licence (SA) Petroleum Resources Management System Petroleum Resource Rent Tax Q1 FY23 First quarter of FY23 Produces gas from licences VIC/L1(V), which contain the Halladale, Black Watch and Speculant nearshore gas fields, VIC/L007745(V), which contains the Enterprise gas field, and licences VIC/L23, T/L2, T/L3 and T/L4 which contain the Geographe and Thylacine offshore gas fields. Beach also holds non-producing offshore licenses T/30P, VIC/P42(V), VIC/P43, VIC/P73 and VIC/P007192(V) Western Australia reporting segment Waitsia Gas Project (Beach 50%, MEPAU 50% and operator) produces gas from the onshore Waitsia gas field in the Perth Basin in licence L1/L2 Webuild Webuild SPA Western Flank Gas Comprises gas production from ex PEL 91 and 106 (Beach 100% and operator) Western Flank Oil Comprises oil production from ex PEL 91 (Beach 100% and operator), ex PEL 92 (Beach 75% and operator, Cooper Energy 25%) and ex PEL 104/111 (Beach 100% and operator) YEJ22 YEJ23 30 June 2022 30 June 2023 123 Subsidiary Company Tenement % Impress (CB) 85% Springfield 15% Impress (CB) 85% Springfield 15% PPL 242 (Growler Oil Field) 100% PPL 243 (Mustang Oil Field) 100% Schedule of Tenements Cooper/Eromanga – Queensland Subsidiary Company Tenement Maw 6.50% Delhi 32% Delhi 22.5% BE(OP)L 25% Delhi 20% BE(OP)L 25% Delhi 25.2% BE(OP)L 27% Delhi Delhi Delhi 28.8% BE(OP)L 10% Delhi Delhi 23.2% BE(OP)L 16.7375% ATP 1189 ex ATP 259 (Naccowlah Block) (1) ATP 1189 ex ATP 259 (Aquitaine A Block) (2) ATP 1189 ex ATP 259 (Aquitaine B Block) (3) ATP 1189 ex ATP 259 (Aquitaine C Block) (4) ATP 1189 ex ATP 259 (Innamincka Block) (5) ATP 1189 ex ATP 259 (Total 66 Block) (6) ATP 1189 ex ATP 259 (Wareena Block) (7) PL 55 (50/40/10) SWQ Gas Unit (8) Circumpacific ATP 940 DLS PLs (Tintaburra Block) (9) Cooper/Eromanga – South Australia BPT BPT BPT BPT BPT BPT Impress (CB) BPT 40% GAOG 60% 40% 39.9375% BPT 40% GAOG 60% 100% 40% BPT 40% GAOG 60% BPT 50% GAOG 50% Subsidiary Company Tenement % Impress (CB) PPL 203 (Acrasia Oil Field) 100% BPT BPT Impress (CB) PPL 204 (Sellicks Oil Field) PPL 205 (Christies Oil Field) PPL 208 (Derrilyn West Field) (10) Impress (CB) PPL 209 (Harpoono Field) PPL 210 (Aldinga Oil Field) PPL 211 (Regg Sprigg West Field) (11) PPL 212 (Kiana Oil Field) 100% BPT Impress (CB) BPT 40% DLS 30% GAOG 30% Impress (CB) Impress (CB) Impress (CB) Impress (CB) PPL 213 (Mirage Field) PPL 214 (Ventura Field) PPL 215 (Toparoa Field) (10) PPL 217 (Arwon West Field) Impress (CB) PPL 218 (Arwon East Field) PPL 220 (Callawonga Oil Field) PPL 224 (Parsons Oil Field) PPL 239 (Middleton/ Brownlow Fields) PPL 240 (Snatcher Oil Field) PPL 241 (Vintage Crop Field) BPT BPT BPT 50% GAOG 50% Impress (CB) 85% Springfield 15% Impress (CB) 124 Impress (CB) 85% Springfield 15% BPT 40% GAOG 60% BPT 40% GAOG 60% BPT 40% GAOG 60% Impress (CB) 85% Springfield 15% Impress (CB) 85% Springfield 15% Impress (CB) 85% Springfield 15% Impress (CB) 85% Springfield 15% Impress (CB) 57% Acer 43% Impress (CB) DLS (513) 40% Impress (CB) 85% Springfield 15% Impress (CB) BPT 25% DLS Gas 30% GAOG 45% BPT % 38.5% 47.5% 45% 52.2% 30% 30% 38.8% 75% 75% 100% 100% 50% 100% 100% 100% 100% 100% 100% 75% 75% 100% 100% 100% PPL 245 (Butlers Oil Field) PPL 246 (Germein Oil Field) PPL 247 (Perlubie Oil Field) PPL 248 (Rincon Oil Field) PPL 249 (Elliston Oil Field) PPL 250 (Windmill Oil Field) PPL 251 (Burruna Field) PPL 253 (Bauer/Bauer- North/Chiton/Arno Oil Fields) PPL 254 (Congony/ Kalladeina/Sceale Oil Fields) PPL 255 (Hanson/Snelling Oil Fields) PPL 257 (Canunda/ Coolawang Fields) 75% 75% 75% 75% 75% 75% 100% 100% 100% 100% 100% PPL 258 (Spitfire Oil Field) 100% PPL 260 (Stunsail Oil Field) 100% PPL 261 (Pennington Oil Field) PPL 262 (Balgowan Oil Field) PPL 263 (Martlett North Oil Field) 100% 100% 100% PPL 264 (Martlett Oil Field) 100% PPL 265 (Marauder Oil Field) 100% PPL 266 (Breguet Oil Field) 100% PPL 268 (Vanessa Gas Field) PPL 270 (Gemba Field) PPL 275 (Yarowinnie Gas Field) PRL 15 (Growler Block) PRL 16 (Dunoon-2) PRL 26 (Udacha Unit) PRLs 35, 37, 38, 41, 43–45, 48, 49 (ex PEL 218 Permian) 100% 100% 40% 100% 100% 100% 100% Impress (CB) Impress (CB) PRL 73 (ex PEL 90C) 33.3333% PRLs 76 to 77 (ex PEL 102) 33.3333% Beach Energy Limited Annual Report 2023 Subsidiary Company Tenement % Otway – South Australia Impress (CB) PRLs 78 to 84 (ex PEL 113) 33.3333% Subsidiary Company Tenement BPT Impress (CB) Impress (CB) Impress (CB) Impress (CB) Impress (CB) BPT 50% GAOG 50% GAOG Impress (CB) 57% Acer 43% Impress (CB) 85% Springfield 15% BPT 40% GAOG 60% Acer BPT 40% DLS 20% GAOG 40% DLS (513) Impress (CB) Impress (CB) Impress (CB) 57% Acer 43% Impress (CB) Ambassador Impress (CB) BPT BPT 25% DLS Gas 30% GAOG 45% BPT 50% GAOG 50% BPT 40% GAOG 60% BPT 40% DLS 20% GAOG 40% BPT Delhi 17.14% BE(OP)L 10.536% Delhi 17.14% BE(OP)L 10.536% Delhi 20.21% BE(OP)L 13.19% Delhi 20.21% BE(OP)L 13.19% PRLs 85 to 104 (ex PEL 92) 75% PRLs 105, 106, 116, (ex PEL 115) PRLs 108 to 110 (ex PEL 105) 33.3333% 33.3333% PRL 117 (ex PEL 115) 100% PRL 120 (ex PEL 514) 33.3333% PRL 128 (ex PEL 514) PRLs 129 and 130 (ex PEL 106) PRLs 131 to 134 (ex PEL 632) PRL 135 (Vanessa Gas Field) PRLs 136 to 150 (ex PEL 104 and PEL 111) 100% 100% 40% 100% 100% PRLs 151 to 172 (ex PEL 91) 100% PRLs 173 to 174 (ex PEL 101) PRLs 175 to 179 (ex PEL 107) PRLs 191 to 206 (ex PEL 513) PRLs 210, 212 to 220 (ex PEL 637) PRLs 221 to 230 (ex PEL 638) PRLs 238 to 244 (ex PEL 182) PEL 516 PEL 570 PEL 639 GSEL 634 (ex PEL 92) GSEL 645 (ex Udacha Unit) GSEL 646 (ex PEL 106) GSEL 648 (ex PEL 91) 100% 100% 40% 33.3333% 33.3333% 100% 33.3333% 33.3333% 100% 75% 100% 100% 100% ADE ADE ADE ADE ADE ADE ADE ADE ADE ADE ADE PEL 494 GSEL 654 PPL 62 (Katnook) PPL 168 (Redman) PPL 202 (Haselgrove) PRL 1 (Wynn) PRL 2 (Limestone Ridge) PRL 32 (ex PEL 255) GSRL 27 PEL 680 GEL 780 Onshore Otway – Victoria Subsidiary Company Tenement BPT BPT BPT PPL 6 (McIntee Gas Field) PPL 9 (Lavers Gas Field) PEP 168 Nearshore Otway Victoria Subsidiary Company BE(OP)L BE(OP)L BE(OP)L BE(PO)L Tenement ViICL1(V) VIC/P42(V) VIC/P007192(V)(14) VIC/L007745(V) Offshore Otway – Victoria Subsidiary Company Tenement BE(OP)L BE(OP)L BE(OP)L 55% BE(Ot)L 5% VIC/P43 VIC/P73 VIC/L23 Browse – Western Australia % 70% 70% 100% 100% 100% 100% 100% 70% 100% 70% 100% % 10% 10% 50% % 60% 60% 60% 60% % 60% 60% 60% GSEL 653 (ex PEL 107) 100% BPT Subsidiary Company Tenement WA-80-R % 9.7637% GSLs 1 to 4 PPL 194 Reg Sprigg West Unit 33.4% 27.676% Patchawarra East (12) 27.676% Fixed Factor Agreement (13) 33.4% SA Unit 33.4% Bonaparte Basin – Western Australia Subsidiary Company Tenement BE(OP)L BE(B)PL BE(O)PL BE(B)PL WA-454-P WA-6-R14 WA-545-P WA-548-P % 50% 0% 10% 5.75% 125 Schedule of Tenements Otway (Offshore) – Tasmania Subsidiary Company Tenement BE(OP)L BE(OP)L 55% BE(Ot)L 5% BE(OP)L 55% BE(Ot)L 5% BE(OP)L 55% BE(Ot)L 5% T/30P T/L2 (Thylacine) T/L3 (Thylacine South) T/L4 (Thylacine West Extension) Bass Basin – Tasmania Subsidiary Company Tenement BE(OP)L 72.5% BE(BG)L 5% BPT 11.25% BE(OP)L 79% BPT 11.25% BE(OP)L 79% BPT 11.25% BE(OP)L 79% BPT 11.25% T/L1 (Yolla) T/RL2 T/RL4 T/RL5 Perth Basin – Western Australia Subsidiary Company Tenement BE(PB)PL BE(PB)PL BE(PB)PL EP 320 L11/L22 (Beharra Springs) L1/L2 (Waitsia Excluding Dongara, Mondarra and Yardarino) Bonaparte – Northern Territory Subsidiary Company Tenement BE(B)PL BE(B)PL NT/P88 NT/RL114 % 100% 60% 60% 60% % 88.75% 90.25% 90.25% 90.25% % 50% 50% 50% % 5.75% 0% (1) The Naccowlah Block consists of ATP 1189 ex ATP 259 (Naccowlah) and PLs 23–26, 35, 36, 62, 76–78, 79 (PLA 1078 replacement), 82 (PL 1079 replacement), 87 (PLA 1080 replacement), 133 (PLA 1085 replacement), 149, 175, 181, 182, 287, 302, 495, 496, 1026. PLAs 1047, 1060, 1078, 1079, 1085, 1093. Note sub-leases of PLs (gas) to SWQ Unit, and PCAs 269, 271. (2) The Aquitaine A Block consists of ATP 1189 ex ATP 259 (Aquitaine A) and PLs 86, 131, 146, 177, 254, 1051, PLA 1058. Note sub-leases of part PLs (gas) to SWQ Unit and PCA 276. (3) The Aquitaine B Block consists of ATP 1189 ex ATP 259 (Aquitaine B) and PLs 59 60 (PLA 1072 replacement), 61 (PLA 1073 replacement), 81, 83 (PLA 1092 replacement), 85, 108, 111 (PLA 1090 replacement), 112, 132 (PLA 1091 replacement), 135, 139, 147 (PLA 1075 replacement), 151, 152, 155, 205 (PLA 1076 replacement), 288, 508, 509, 1013, 1014, 1035. PLA 1108. Note sub-leases of part of PLs (gas) to SWQ Unit and PCAs 248, 270, 251, 281. (4) The Aquitaine C Block consists of ATP 1189 ex ATP 259 (Aquitaine C) and PLs 138 and 154. (5) The Innamincka Block consists of ATP 1189 ex ATP 259 (Innamincka) and PLs 58, 80, 136, 137, 156, 159, 249, 1087. Note sub-leases of part PLs (gas) to SWQ Unit and PCAs 278, 282, 28. (6) The Total 66 Block consists of ATP 1189 ex ATP 259 (Total 66) and PLs 34, 37, 63, 68, 75, 84, 88, 110 (PL 497 replacement), 129, 130, 134, 140, 142, 143 (PLA replacement 1057), 144, 150, 186, 193 (PLA 513 replacement), 241, 255, 301, 497, 502, 1046, 1056 and 1077. Note sub-leases of part of PLs (gas) to SWQ Unit and PCAs 252, 253, 254, 275, 279, 280. (7) The Wareena Block consists of ATP 1189 ex ATP 259 (Wareena) and PLs, 141, 145, 148, 153, 158 (PLA 1105 replacement), 187, 1016, 1054, 1055 and 1107. Note sub-leases of part of PLs (gas) to SWQ Unit and PCAs 250, 251, 268, 272, 273, 274, 277, 281. (8) The SWQ Gas Unit consists of subleases of PLs within the gas production area of Naccowlah Block, Aquitaine A Block, Aquitaine B Block, Innamincka Block, Wareena Block and Total 66 Block. (9) Ex ATP 299 (Tintaburra) consists of PLs 29, 38, 39, 52, 57, 95, 169, 170, 295, PLA 1027, PLA 1029. (10) Derrilyn Unitisation Agreement for PPL 206, PPL 208 and PPL 215 – Impress (CB) 35% interest. (11) Regg Sprigg West Unitisation Agreement for well consists of PPL 211 (Impress CB) and PPL 194 (Patchwarra East). (12) Patchawarra East consists of PPLs 26, 76–77, 118, 121 –123, 125, 131, 136, 147, 152, 156, 158, 167, 182, 187, 194, 201 and 229. (13) The Fixed Factor Agreement consists of PPLs 6–20, 22–25, 27, 29–33, 35–48, 51–61, 63–70, 72–75, 78–81, 83–84, 86–92, 94–95, 98–111, 113–117, 119–120, 124, 126–130, 132–135, 137–140, 143–146, 148–151, 153–155, 159–166, 172, 174–180, 189–190, 193, 195–196, 228 and 230–238. (14) Transfer of interest subject to Government approvals. Tenements Acquired ADE GEL 780 DLS (513) 40% PPL 275 (Yarowinnie Gas Field) Taranaki Basin – New Zealand Tenements Divested Subsidiary Company Tenement BERNZKL 32.1875% Kupe Mining No.1 Ltd 17.8125% PML 38146 (Kupe) 126 % 50% BPT BPT BPT 50% Impress (BCB) 15% Impress (CB) Impress (CB) Impress (CB) Impress (CB) Impress (CB) Impress (CB) PEL 95 PEL 630 PEL 94 PPL 207 (Worrior Field) PPL 221 (Padulla Field) PRLs 183 to 190 (ex PEL 110) PRLs 207 to 209 (ex PEL 100) PRLs 231 to 233 and 23713 (ex PEL 93) PRLs 245 to 246 (ex PEL 90k) Impress (CB) 57% Acer 43% PEL 182 Beach Energy Limited Annual Report 2023 Shareholder Information Share details – Distribution as at 2 August 2023 Range 1 – 1000 1,001 – 5,000 5,001 – 10,000 10,001 – 100,000 100,001 Over Rounding Total Unmarketable Parcels Minimum $500.00 parcel at $1.6250 per unit Total holders Units % Units 8,925 11,741 5,185 7,548 554 4,492,416 32,115,173 39,358,256 213,266,946 1,992,100,865 0.20 1.41 1.73 9.35 87.32 -0.01 33,953 2,281,333,656 100.00 Minimum Parcel Size 308 Holders 2,485 Units 249,858 Substantial shareholders as disclosed by notices received by Beach as at 2 August 2023 Name Seven Group Holdings and others Australian Capital Equity Pty Ltd, Wroxby Pty Ltd, North Aston Pty Ltd and others (ACE Group); Ashblue Holdings Pty Ltd, Tiberius (Seven Investments) Pty Ltd, Tiberius Pty Ltd and others (Tiberius Group); Mr Kerry Matthew Stokes AC and Kemast Investments Pty Ltd Number of voting shares held Date of Notice 684,774,056 30 April 2021 684,774,056 30 April 2021 Twenty largest shareholders as at 2 August 2023 Rank Name Units % Units HSBC CUSTODY NOMINEES (AUSTRALIA) LIMITED NETWORK INVESTMENT HOLDINGS PTY LTD NETWORK INVESTMENT HOLDINGS PTY LTD CITICORP NOMINEES PTY LIMITED J P MORGAN NOMINEES AUSTRALIA PTY LIMITED NATIONAL NOMINEES LIMITED WESTRAC HOLDINGS PTY LIMITED NETWORK INVESTMENT HOLDINGS PTY LTD BNP PARIBAS NOMS PTY LTDNETWORK INVESTMENT HOLDINGS PTY LTD MR ROBERT LEE PETERSEN HSBC CUSTODY NOMINEES (AUSTRALIA) LIMITED SANDHURST TRUSTEES LTD NETWORK INVESTMENT HOLDINGS PTY LTD CITICORP NOMINEES PTY LIMITED MCCUSKER HOLDINGS PTY LTD MR KENNETH JOSEPH HALL BNP PARIBAS NOMINEES PTY LTD HUB24 CUSTODIAL SERV LTD MCCUSKER FOUNDATION LTD AYERSLAND PTY LTD 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Totals: Top 20 holders of FULLY PAID ORDINARY SHARES (Total) 501,265,795 333,511,087 250,000,000 231,463,814 199,295,109 89,401,159 34,220,004 34,127,698 29,430,148 18,742,950 18,308,155 16,359,481 14,875,268 14,172,317 8,441,437 7,000,000 6,310,000 5,868,833 5,500,000 5,120,110 1,823,413,365 21.97 14.62 10.96 10.15 8.74 3.92 1.50 1.50 1.29 0.82 0.80 0.72 0.65 0.62 0.37 0.31 0.28 0.26 0.24 0.22 79.93 Total Remaining Holders Balance 457,920,291 20.07 127 Corporate Information Annual General Meeting For information about the Annual General Meeting, please visit: beachenergy.com.au/agm Registered Office Level 8, 80 Flinders Street ADELAIDE SA 5000 Telephone: (08) 8338 2833 Facsimile: (08) 8338 2336 Email: info@beachenergy.com.au Share Registry – South Australia Computershare Investor Services Pty Ltd Level 5, 115 Grenfell St ADELAIDE SA 5000 Telephone: 1300 556 161 (within Australia) +61 (03) 9415 4000 (outside Australia) Contact Computershare – www.investorcentre.com/contact Auditors Ernst & Young Level 12/121 King William Street ADELAIDE SA 5000 Securities Exchange Listing Beach Energy Limited shares are listed on the ASX Limited (ASX Code: BPT) Beach Energy Limited ABN 20 007 617 969 Website www.beachenergy.com.au Corporate Directory Chairman Glenn Davis LLB, BEc, FAICD Independent non-executive Directors Bruce Clement BEng (Civil) Hons, BSc, MBA Executive Sally-Anne Layman BEng (Mining) Hons, BCom, CPA, MAICD Independent non-executive Peter Moore PhD, BSc (Hons), MBA, GAICD Independent non-executive Richard Richards BComs/Law (Hons), LLM, MAppFin, CA, Admitted Solicitor Non-executive Ryan Kerry Stokes, AO BComm, FAIM Non-executive Margaret Hall BEng (Met) Hons, MIEAust, GAICD, SPE Alternate (non-executive) director for Ryan Stokes Joint Company Secretaries Susan Jones LLB (Hons), General Counsel David Lim LLB, BEc 128 Beach Energy Limited Annual Report 2023